Integrated resid deasphalting and gasification

ABSTRACT

Systems and methods are provided for integration of use deasphalted resid as a feed for fuels and/or lubricant base stock production with use of the corresponding deasphalter rock for gasification to generate hydrogen and/or fuel for the fuels and/or lubricant production process. The integration can include using hydrogen generated during gasification as a fuel to provide heat for solvent processing and/or using the hydrogen for hydroprocessing of deasphalted oil.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims priority to U.S. Provisional Application Ser.No. 62/271,543 filed Dec. 28, 2015, which is herein incorporated byreference in its entirety.

This application is related to five (5) other co-pending non-provisionalU.S. applications, filed on even date herewith, and identified by thefollowing U.S. Patent Application Nos. and titles: Ser. No. 15/390,784entitled “Bright Stock And Heavy Neutral Production From ResidDeasphalting”; Ser. No. 15/390,790 entitled “Bright Stock ProductionFrom Low Severity Resid Deasphalting”; Ser. No. 15/390,794 entitled“Bright Stock Production From Low Severity Resid Deasphalting”; Ser. No.15/390,943 entitled “Bright Stock Production From Deasphalted Oil”; andSer. No. 15/390,896 entitled “Sequential Deasphalting For Base StockProduction”. Each of these co-pending US applications is herebyincorporated by references herein in their entirety.

FIELD

Systems and methods are provided for production of lubricant oil basestocks from deasphalted oils produced by low severity deasphalting ofresid fractions.

BACKGROUND

Lubricant base stocks are one of the higher value products that can begenerated from a crude oil or crude oil fraction. The ability togenerate lubricant base stocks of a desired quality is often constrainedby the availability of a suitable feedstock. For example, mostconventional processes for lubricant base stock production involvestarting with a crude fraction that has not been previously processedunder severe conditions, such as a virgin gas oil fraction from a crudewith moderate to low levels of initial sulfur content.

In some situations, a deasphalted oil formed by propane deasphalting ofa vacuum resid can be used for additional lubricant base stockproduction. Deasphalted oils can potentially be suitable for productionof heavier base stocks, such as bright stocks. However, the severity ofpropane deasphalting required in order to make a suitable feed forlubricant base stock production typically results in a yield of onlyabout 30 wt % deasphalted oil relative to the vacuum resid feed.

U.S. Pat. No. 3,414,506 describes methods for making lubricating oils byhydrotreating pentane-alcohol-deasphalted short residue. The methodsinclude performing deasphalting on a vacuum resid fraction with adeasphalting solvent comprising a mixture of an alkane, such as pentane,and one or more short chain alcohols, such as methanol and isopropylalcohol. The deasphalted oil is then hydrotreated, followed by solventextraction to perform sufficient VI uplift to form lubricating oils.

U.S. Pat. No. 7,776,206 describes methods for catalytically processingresids and/or deasphalted oils to form bright stock. A resid-derivedstream, such as a deasphalted oil, is hydroprocessed to reduce thesulfur content to less than 1 wt % and reduce the nitrogen content toless than 0.5 wt %. The hydroprocessed stream is then fractionated toform a heavier fraction and a lighter fraction at a cut point between1150° F.-1300° F. (620° C.-705° C.). The lighter fraction is thencatalytically processed in various manners to form a bright stock.

U.S. Pat. No. 6,241,874 describes a system and method for integration ofsolvent deasphalting and gasification. The integration is based on usingsteam generated during the gasification as the heat source forrecovering the deasphalting solvent from the deasphalted oil product.

SUMMARY

In various aspects, systems and methods are provided for integration ofuse deasphalted resid as a feed for fuels and/or lubricant base stockproduction with use of the corresponding deasphalter rock forgasification to generate hydrogen and/or fuel for the fuels and/orlubricant production process. The integration can include using hydrogengenerated during gasification as a fuel to provide heat for solventprocessing and/or using the hydrogen for hydroprocessing of deasphaltedoil.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 schematically shows an example of a configuration for processinga deasphalted oil to form a lubricant base stock.

FIG. 2 schematically shows another example of a configuration forprocessing a deasphalted oil to form a lubricant base stock.

FIG. 3 schematically shows another example of a configuration forprocessing a deasphalted oil to form a lubricant base stock.

FIG. 4 shows results from processing a pentane deasphalted oil atvarious levels of hydroprocessing severity.

FIG. 5 shows results from processing deasphalted oil in configurationswith various combinations of sour hydrocracking and sweet hydrocracking.

FIG. 6 schematically shows an example of a configuration for catalyticprocessing of deasphalted oil to form lubricant base stocks.

FIG. 7 schematically shows an example of a configuration for integrationof gasification of deasphalter rock with deasphalting andhydroprocessing of a feed.

FIG. 8 shows results from flow rate testing of deasphalter rock pelletsgenerated from pentane deasphalting.

DETAILED DESCRIPTION

All numerical values within the detailed description and the claimsherein are modified by “about” or “approximately” the indicated value,and take into account experimental error and variations that would beexpected by a person having ordinary skill in the art.

Integration of Rock Gasification with Lubricant Production

In various aspects, systems and methods are provided for integration ofuse deasphalted resid as a feed for lubricant base stock production withuse of the corresponding deasphalter rock for gasification to generatehydrogen and/or fuel for the lubricant production process. Optionally,the methods can be further facilitated by use of an anti-tack agent onthe deasphalter rock to allow for improved flow characteristics whenpassing the deasphalter rock into the gasification system.

Solvent deasphalting processes can produce at least two types of productfractions. A first type of product fraction can correspond todeasphalted oil. This is generally the desired product from solventdeasphalting, as the deasphalted oil can serve as a feed for productionof a high value product. In various aspects, the deasphalted oil can beused as a feed for production of lubricant base stocks. In particular,solvent deasphalting can be performed on a feed including a 566° C.+portion to generate a deasphalted oil with a yield of at least about 50wt %, or at least about 65 wt %, or at least about 75 wt %, relative toa weight of the feed. This deasphalted oil (or at least a portionthereof) can then be used as the input feed for lubricant base stockproduction, such as production of bright stock.

As second type of product generated by solvent deasphalting is aresidual product, often referred to as deasphalter rock. Deasphalterrock is generally a difficult to process fraction with regard togenerating higher value hydrocarbon products, and this difficulty can befurther increased when deasphalting is performed to generate deasphaltedoil yields of greater than 50 wt %. In various aspects, the difficultyin creating higher value hydrocarbon products can be overcome by insteadusing gasification to convert the deasphalter rock into syngas. Thissyngas can be used directly as a fuel and/or the syngas can bedesulfurized to provide a low sulfur fuel and/or the syngas can beshifted to increase the hydrogen content for subsequent use inhydroprocessing. The gasification process can also generate substantialamounts of steam that can be used to provide heat for various streams ina hydroprocessing configuration.

Conventionally, one of the difficulties in performing gasification ondeasphalter rock was handling the amount of by-products created bygasification in a useful manner. At conventional levels of deasphaltedoil lift, the portion of deasphalted oil may correspond to only 40 wt %or less of the initial feed, leaving behind 60 wt % or more ofdeasphalter rock. Performing gasification on this amount of deasphalterrock resulted in production of substantial amounts of both steam andsyngas. The system in U.S. Pat. No. 6,241,874 provided a method forusing the steam generated during gasification in an integrated manner byusing the steam to provide heat for recovery of the deasphaltingsolvent. This avoided the need to simply shunt the heat from excesssteam into the atmosphere. However, the syngas product remains unused insuch a conventional configuration, which can result in flaring in orderto dispose of the stream.

In contrast to conventional methods, the systems and methods describedherein can allow for integration of the syngas product generated fromgasification for use in various aspects. A substantial portion of thesyngas product can be used, for example, to provide hydrogen for deephydroprocessing (such as hydrocracking) of the deasphalted oil. Theremaining syngas can be used as fuel to, for example, provide heat forsolvent deasphalting (including recovery of solvent) and/or additionalheat for the hydroprocessing of the deasphalted oil. If excess hydrogenand/or syngas remains, the excess hydrogen can be used to power a gasturbine to generate electric power. Optionally, the steam generated bygasification can be used for heat exchange and/or recovered for electricpower generation.

FIG. 7 shows an example of the various types of process integration thatcan be achieved when processing a heavy oil feed using a process flowthat includes a deasphalting process. In FIG. 7, an initial feed 905 isintroduced into a deasphalting unit. The feed can include a 566° C.+portion, such a feed having a T50 distillation point of 566° C. orgreater (i.e., at least 50 wt % boils at greater than 566° C.), or a T40distillation point of 566° C. or greater, or a T30 distillation point of566° C. or greater, or a T20 distillation point of 566° C. or greater.Any convenient type of deasphalting can be performed, such asdeasphalting using a C₃-C₇ solvent. In some preferred aspects, thedeasphalting can involve a C₄₊ solvent. Additionally or alternately, insome preferred aspects, the solvent deasphalting conditions can beselected to generate a yield of deasphalted oil of at least 65 wt %, orat least 75 wt %, relative to the initial feed. In FIG. 7, thedeasphalting unit 910 is configured to separate the feed 905 intodeasphalted oil 915 and rock 917. In other aspects, one or moreadditional fractions could be generated by a deasphalting stage, such asby performing sequential deasphalting to form an intermediate resinfraction and/or multiple deasphalted oils.

Performing solvent deasphalting can require a substantial amount ofenergy to heat the feed and the solvent to the desired solventdeasphalting temperature and/or to recover solvent from the deasphaltedoil and deasphalter rock products. It is noted that the solvent removaltowers 922 and 942 for recovering solvent from the deasphalted oil 915and deasphalter rock 917, respectively, are shown separately. The heatfor operating the deasphalting unit 910 and/or recovering solvent insolvent removal towers 922 and 942 can be provided, for example, bydeasphalting unit furnace 918. The fuel 919 for deasphalting unitfurnace 918 can be provided by a fuel source 980, where the fuel forfuel source 980 can correspond to syngas derived from gasification ofdeasphalter rock.

Deasphalter rock fraction 917 can be passed into gasifier 940 (oranother type of gasification stage). If rock fraction 917 is a fluid asit exits the solvent deasphalting unit, the rock fraction 917 can bemaintain at an elevated temperature to facilitate transport of the rockinto gasifier 940. Alternatively, if at least a portion of rock fraction917 is a solid, the solid can be crushed to form small particles toallow for fluidization and transport of the rock into gasifier 940.

During gasification, the rock fraction 917 can be exposed to oxygenand/or steam at a temperature of 700° C. or greater, or 1000° C. orgreater. This can convert the rock into syngas, which is a mixture ofCO, CO₂, H₂O, and H₂. The process is exothermic, with the rock fraction917 serving as both the feed for forming the gasifier effluent and thefuel for heating the reaction environment. Due to the sulfur content ofa typical deasphalter rock fraction, the resulting gasifier effluent canalso include H₂S and/or SO_(x), so that the syngas in the effluentcorresponds to sour syngas. In addition to syngas, the gasificationprocess can also generate steam 941, optionally at elevated pressure.Steam 941 can be used for heat exchange with any convenient refinerysteam and/or the steam can be used in a heat recovery generator toproduce electric power.

The sour syngas 945 can be directly used as a fuel by fuel source 980.Additionally or alternately, the sour syngas 945 can be passed throughan H₂S removal stage 960, such as a water wash or amine wash, to removesulfur compounds. Still further additionally or alternately, at least aportion of the syngas can be shifted 950 to form an enriched or shiftedsyngas 955 with an increased hydrogen content. The optional shiftingand/or optional sulfur removal from the syngas can be performed in anyconvenient order. A portion of the shifted syngas 955 and/or a portion967 of the desulfurized syngas 965 can be used as part of fuel source980. It is noted that any desulfurized syngas that is used as a fuelsource 980 can correspond to a low sulfur emission fuel.

Optionally, one or more water gas shift reaction stages can be includedto convert CO and H₂O into CO₂ and H₂, if desired. The amount of H₂ canbe increased, for example, by using a water gas shift reactor at lowertemperature to convert H₂O and CO into H₂ and CO₂. Alternatively, thetemperature can be raised and the water-gas shift reaction can bereversed, producing more CO and H₂O from H₂ and CO₂. If desired, H₂O canbe added to and/or removed from a gasifier output stream prior to awater gas shift reaction stage in order to help drive the water gasshift equilibrium in a desired direction. One option for operating thewater gas shift reactor can be to expose the anode output stream to asuitable catalyst, such as a catalyst including iron oxide, zinc oxide,copper on zinc oxide, or the like, at a suitable temperature, e.g.,between about 190° C. to about 210° C. Optionally, the water-gas shiftreactor can include two stages for reducing the CO concentration in agasifier output fraction, with a first higher temperature stage operatedat a temperature from at least about 300° C. to about 375° C. and asecond lower temperature stage operated at a temperature of about 225°C. or less, such as from about 180° C. to about 210° C.

If a shifted, sweet syngas 965 is formed, the shifted, sweet syngas canbe passed through a hydrogen purification stage 970, such as a swingadsorption reactor, for production of a higher purity hydrogen stream975. The higher purity hydrogen stream 975 can then be compressed 974 toform a hydrogen stream 921 that is suitable for use as ahydrogen-containing stream in a hydroprocessing reactor. If the hydrogenpurification 975 is performed using a swing reactor, the swing reactorcan also generate a low pressure hydrogen-containing purge stream 977that can be suitable for use as a fuel source 980. An example of a swingreactor is a pressure swing adsorption reactor, such as a rapid cyclepressure swing adsorption reactor. Any convenient type of swingreactor(s) can be used for hydrogen purification stage 970. This caninclude using a plurality of swing reactors to provide continuouspurification (i.e., one or more swing reactors can operate in theadsorption portion of the process cycle while other swing reactors arein the regeneration portion of the process cycle). In typical operation,a swing adsorption reactor can provide a higher pressure (primary)purified hydrogen product along with a lower pressure purge product. Thepurge product can also include substantial hydrogen content, but is alower pressure stream that is produced during the regeneration portionof a swing cycle. In various aspects, the hydrogen used for purge of theswing reactor can correspond to a portion of the higher pressurepurified hydrogen product generated by the swing reactor, and thereforethe purge hydrogen stream can correspond to a portion of the hydrogengenerated by the gasifier.

Fuel source 980 can be used to provide fuel for a variety of heaters inan integrated processing environment. Examples of processing units thatrequire additional heat include deasphalting unit 910 andhydroprocessing unit(s) 920. Optionally, any excess fuel from fuelsource 980 can be used to generate additional electric power, such as byusing fuel from fuel source 980 for a gas turbine 930. A gas turbine 930can, for example, comprise a combustion zone for receiving fuel (such ashydrogen) from fuel source 980. The fuel can be combusted in thecombustion zone to allow the turbine to produce electric power.

In various aspects, the deasphalted oil 915 can be used for products925, such as brightstocks, other lubricant base stocks, and/or fuels. Atleast part of the conversion of deasphalted oil 915 into lubricant basestocks can be based on hydroprocessing 920. Hydroprocessing unit 920 inFIG. 7 can represent any convenient number of hydroprocessing units 920.For example, a first hydroprocessing stage may contain demetallization,hydrotreating, and/or hydrocracking catalyst, while a secondhydroprocessing stage may contain hydrocracking, dewaxing, and/orhydrofinishing catalyst. As another example, hydroprocessing unit(s) 920can include demetallization, hydrotreating, and/or hydrocrackingcatalysts, and the deasphalted oil can be exposed to the catalysts underconditions sufficient to reduce the sulfur content of the deasphaltedoil to a desired amount, for example 500 wppm or less, or 200 wppm orless, or 100 wppm or less, or 50 wppm or less, such as down to about 1wppm or lower. This type of deep desulfurization of a deasphalted oilfeed can consume a substantial portion of the hydrogen generated duringgasification in aspects where the amount of deasphalted oil (by weight)generated during deasphalting is equal to or greater than the amount ofdeasphalter rock.

In various aspects, any convenient number of associated heating units928 can also be used. For example, only a single heating unit 928 may beused, or a separate heating unit 928 may be associated with eachhydroprocessing unit 920, or any other convenient combination.

In an integrated system, various processing elements can be in direct orindirect fluid communication. In the exemplary system shown in FIG. 7,gasifier 940 is in direct fluid communication with shift reactor 950, asthere is not another intervening process element between gasifier 940and shift reactor 950. Gasifier 940 is in indirect fluid communicationwith purification stage 970, as any gas flow from gasifier 940 topurification stage 970 passes through shift reactor 950 and/ordesulfurization stage 960.

An integrated deasphalting, gasification, and hydroprocessing systemsuch as the example shown in FIG. 7 can provide a variety of advantages.Some advantages can be related to allowing a refinery to consume rockwithin a closed system, so that the rock is not only beneficially used,but also has a reduced or minimized need for transport. Becausegasification generates hydrogen at an elevated pressure relative to thepressure of a steam methane reformer, the amount of compression ofhydrogen that is required can be reduced or minimized. The integratedsystem can also allow for utilization of the hydrogen-containing purgestream from the swing reformer without requiring compression, since thepurge stream can be beneficially used as fuel. Still another advantagecan be that use of a gas turbine to generate electric power can allowfor swings in syngas generation to be accounted for without having tostore or flare excess fuel. Thus, the deasphalter rock can continue tobe gasified even when demand for other products fluctuates.

Anti-Tack Agents for Deasphalter Rock

In some aspects, the rock from solvent deasphalting may need to behandled at a temperature where the rock is not a liquid. For example, ifadditional rock from a separate deasphalting process is added to theintegrated processing system, the additional rock may be cooled prior totransport. After cooling, the rock can become solid. To allow forstorage and transport of the solid rock (such as by conveyor belt), thesolid rock can be pelletized, crushed, or otherwise formed into smallpieces.

Although sufficiently small particles of rock can be fluidized, thesolid rock can still have a sticky or tacky nature when pressure isapplied and/or when the temperature is increased. If the rock particlesare stored in a large vessel, for example, the weight of the particlesmay cause a substantial number of the rock particles to agglomerate.This can create difficulties when attempting to fluidize the rockparticles for transport within a processing system.

In various aspects, difficulties with agglomeration of deasphalter rockparticles can be reduced or minimized by applying an anti-tack agent tothe deasphalter rock. For example, an anti-tack agent can be applied torock particles by dusting as the particles are transported on aconveyor. Talc is an example of an anti-tack agent that can reduce orminimize agglomeration of rock particles.

FIG. 8 shows results from flow testing of deasphalter rock particles atvarious temperatures. For the data in FIG. 8, pelletized deasphalterrock from pentane deasphalting was stored at a temperature prior toattempting to flow the pellets through a funnel. A comparison was thenmade between the flow rate of the particles through the funnel at roomtemperature versus the flow rate at a second temperature. The results inFIG. 8 show the ratio of the flow rate at the elevated temperature tothe flow rate at room temperature.

As shown in FIG. 8, all of the samples including the anti-tack agent hadsubstantially the same flow rate at room temperature and the elevatedtemperature. By contrast, for the pellets without the anti-tack agent,elevated temperatures of 60° C. and 70° C. resulted in clogging of thefunnel due to agglomeration. This resulted in the ratio of flow ratesbeing effectively zero, due to lack of complete flow through the funnel.This shows that use of an anti-tack agent can reduce or minimizeagglomeration under conditions that would otherwise lead toagglomeration of deasphalter coke particles.

Overview of Lubricant Production from Deasphalted Oil

In various aspects, methods are provided for producing Group I and GroupII lubricant base stocks, including Group I and Group II bright stock,from deasphalted oils generated by low severity C₄₊ deasphalting. Lowseverity deasphalting as used herein refers to deasphalting underconditions that result in a high yield of deasphalted oil (and/or areduced amount of rejected asphalt or rock), such as a deasphalted oilyield of at least 50 wt % relative to the feed to deasphalting, or atleast 55 wt %, or at least 60 wt %, or at least 65 wt %, or at least 70wt %, or at least 75 wt %. The Group I base stocks (including brightstock) can be formed without performing a solvent extraction on thedeasphalted oil. The Group II base stocks (including bright stock) canbe formed using a combination of catalytic and solvent processing. Incontrast with conventional bright stock produced from deasphalted oilformed at low severity conditions, the Group I and Group II bright stockdescribed herein can be substantially free from haze after storage forextended periods of time. This haze free Group II bright stock cancorrespond to a bright stock with an unexpected composition.

In various additional aspects, methods are provided for catalyticprocessing of C₃ deasphalted oils to form Group II bright stock. FormingGroup II bright stock by catalytic processing can provide a bright stockwith unexpected compositional properties.

Conventionally, crude oils are often described as being composed of avariety of boiling ranges. Lower boiling range compounds in a crude oilcorrespond to naphtha or kerosene fuels. Intermediate boiling rangedistillate compounds can be used as diesel fuel or as lubricant basestocks. If any higher boiling range compounds are present in a crudeoil, such compounds are considered as residual or “resid” compounds,corresponding to the portion of a crude oil that is left over afterperforming atmospheric and/or vacuum distillation on the crude oil.

In some conventional processing schemes, a resid fraction can bedeasphalted, with the deasphalted oil used as part of a feed for forminglubricant base stocks. In conventional processing schemes a deasphaltedoil used as feed for forming lubricant base stocks is produced usingpropane deasphalting. This propane deasphalting corresponds to a “highseverity” deasphalting, as indicated by a typical yield of deasphaltedoil of about 40 wt % or less, often 30 wt % or less, relative to theinitial resid fraction. In a typical lubricant base stock productionprocess, the deasphalted oil can then be solvent extracted to reduce thearomatics content, followed by solvent dewaxing to form a base stock.The low yield of deasphalted oil is based in part on the inability ofconventional methods to produce lubricant base stocks from lowerseverity deasphalting that do not form haze over time.

In some aspects, it has been discovered that using a mixture ofcatalytic processing, such as hydrotreatment, and solvent processing,such as solvent dewaxing, can be used to produce lubricant base stocksfrom deasphalted oil while also producing base stocks that have littleor no tendency to form haze over extended periods of time. Thedeasphalted oil can be produced by deasphalting process that uses a C₄solvent, a C₅ solvent, a C₆₊ solvent, a mixture of two or more C₄₊solvents, or a mixture of two or more C₅₊ solvents. The deasphaltingprocess can further correspond to a process with a yield of deasphaltedoil of at least 50 wt % for a vacuum resid feed having a T10distillation point (or optionally a T5 distillation point) of at least510° C., or a yield of at least 60 wt %, or at least 65 wt %, or atleast 70 wt %. It is believed that the reduced haze formation is due inpart to the reduced or minimized differential between the pour point andthe cloud point for the base stocks and/or due in part to forming abright stock with a cloud point of −5° C. or less.

For production of Group I base stocks, a deasphalted oil can behydroprocessed (hydrotreated and/or hydrocracked) under conditionssufficient to achieve a desired viscosity index increase for resultingbase stock products. The hydroprocessed effluent can be fractionated toseparate lower boiling portions from a lubricant base stock boilingrange portion. The lubricant base stock boiling range portion can thenbe solvent dewaxed to produce a dewaxed effluent. The dewaxed effluentcan be separated to form a plurality of base stocks with a reducedtendency (such as no tendency) to form haze over time.

For production of Group II base stocks, in some aspects a deasphaltedoil can be hydroprocessed (hydrotreated and/or hydrocracked), so that˜700° F.+ (370° C.+) conversion is 10 wt % to 40 wt %. Thehydroprocessed effluent can be fractionated to separate lower boilingportions from a lubricant base stock boiling range portion. Thelubricant boiling range portion can then be hydrocracked, dewaxed, andhydrofinished to produce a catalytically dewaxed effluent. Optionallybut preferably, the lubricant boiling range portion can be underdewaxed,so that the wax content of the catalytically dewaxed heavier portion orpotential bright stock portion of the effluent is at least 6 wt %, or atleast 8 wt %, or at least 10 wt %. This underdewaxing can also besuitable for forming light or medium or heavy neutral lubricant basestocks that do not require further solvent upgrading to form haze freebase stocks. In this discussion, the heavier portion/potential brightstock portion can roughly correspond to a 538° C.+ portion of thedewaxed effluent. The catalytically dewaxed heavier portion of theeffluent can then be solvent dewaxed to form a solvent dewaxed effluent.The solvent dewaxed effluent can be separated to form a plurality ofbase stocks with a reduced tendency (such as no tendency) to form hazeover time, including at least a portion of a Group II bright stockproduct.

For production of Group II base stocks, in other aspects a deasphaltedoil can be hydroprocessed (hydrotreated and/or hydrocracked), so that370° C.+ conversion is at least 40 wt %, or at least 50 wt %. Thehydroprocessed effluent can be fractionated to separate lower boilingportions from a lubricant base stock boiling range portion. Thelubricant base stock boiling range portion can then be hydrocracked,dewaxed, and hydrofinished to produce a catalytically dewaxed effluent.The catalytically dewaxed effluent can then be solvent extracted to forma raffinate. The raffinate can be separated to form a plurality of basestocks with a reduced tendency (such as no tendency) to form haze overtime, including at least a portion of a Group II bright stock product.

In other aspects, it has been discovered that catalytic processing canbe used to produce Group II bright stock with unexpected compositionalproperties from C₃, C₄, C₅, and/or C₅₊ deasphalted oil. The deasphaltedoil can be hydrotreated to reduce the content of heteroatoms (such assulfur and nitrogen), followed by catalytic dewaxing under sweetconditions. Optionally, hydrocracking can be included as part of thesour hydrotreatment stage and/or as part of the sweet dewaxing stage.

In various aspects, a variety of combinations of catalytic and/orsolvent processing can be used to form lubricant base stocks, includingGroup II bright stock, from deasphalted oils. These combinationsinclude, but are not limited to:

a) Hydroprocessing of a deasphalted oil under sour conditions (i.e.,sulfur content of at least 500 wppm); separation of the hydroprocessedeffluent to form at least a lubricant boiling range fraction; andsolvent dewaxing of the lubricant boiling range fraction. In someaspects, the hydroprocessing of the deasphalted oil can correspond tohydrotreatment, hydrocracking, or a combination thereof.

b) Hydroprocessing of a deasphalted oil under sour conditions (i.e.,sulfur content of at least 500 wppm); separation of the hydroprocessedeffluent to form at least a lubricant boiling range fraction, andcatalytic dewaxing of the lubricant boiling range fraction under sweetconditions (i.e., 500 wppm or less sulfur). The catalytic dewaxing canoptionally correspond to catalytic dewaxing using a dewaxing catalystwith a pore size greater than 8.4 Angstroms. Optionally, the sweetprocessing conditions can further include hydrocracking, noble metalhydrotreatment, and/or hydrofinishing. The optional hydrocracking, noblemetal hydrotreatment, and/or hydrofinishing can occur prior to and/orafter or after catalytic dewaxing. For example, the order of catalyticprocessing under sweet processing conditions can be noble metalhydrotreating followed by hydrocracking followed by catalytic dewaxing.

c) The process of b) above, followed by performing an additionalseparation on at least a portion of the catalytically dewaxed effluent.The additional separation can correspond to solvent dewaxing, solventextraction (such as solvent extraction with furfural orn-methylpyrollidone), a physical separation such as ultracentrifugation,or a combination thereof.

d) The process of a) above, followed by catalytic dewaxing (sweetconditions) of at least a portion of the solvent dewaxed product.Optionally, the sweet processing conditions can further includehydrotreating (such as noble metal hydrotreating), hydrocracking and/orhydrofinishing. The additional sweet hydroprocessing can be performedprior to and/or after the catalytic dewaxing.

Group I base stocks or base oils are defined as base stocks with lessthan 90 wt % saturated molecules and/or at least 0.03 wt % sulfurcontent. Group I base stocks also have a viscosity index (VI) of atleast 80 but less than 120. Group II base stocks or base oils contain atleast 90 wt % saturated molecules and less than 0.03 wt % sulfur. GroupII base stocks also have a viscosity index of at least 80 but less than120. Group III base stocks or base oils contain at least 90 wt %saturated molecules and less than 0.03 wt % sulfur, with a viscosityindex of at least 120.

In some aspects, a Group 111 base stock as described herein maycorrespond to a Group III+ base stock. Although a generally accepteddefinition is not available, a Group III+ base stock can generallycorrespond to a base stock that satisfies the requirements for a GroupIII base stock while also having at least one property that is enhancedrelative to a Group III specification. The enhanced property cancorrespond to, for example, having a viscosity index that issubstantially greater than the required specification of 120, such as aGroup III base stock having a VI of at least 130, or at least 135, or atleast 140. Similarly, in some aspects, a Group II base stock asdescribed herein may correspond to a Group II+ base stock. Although agenerally accepted definition is not available, a Group II+ base stockcan generally correspond to a base stock that satisfies the requirementsfor a Group II base stock while also having at least one property thatis enhanced relative to a Group II specification. The enhanced propertycan correspond to, for example, having a viscosity index that issubstantially greater than the required specification of 80, such as aGroup II base stock having a VI of at least 103, or at least 108, or atleast 113.

In the discussion below, a stage can correspond to a single reactor or aplurality of reactors. Optionally, multiple parallel reactors can beused to perform one or more of the processes, or multiple parallelreactors can be used for all processes in a stage. Each stage and/orreactor can include one or more catalyst beds containing hydroprocessingcatalyst. Note that a “bed” of catalyst in the discussion below canrefer to a partial physical catalyst bed. For example, a catalyst bedwithin a reactor could be filled partially with a hydrocracking catalystand partially with a dewaxing catalyst. For convenience in description,even though the two catalysts may be stacked together in a singlecatalyst bed, the hydrocracking catalyst and dewaxing catalyst can eachbe referred to conceptually as separate catalyst beds.

In this discussion, conditions may be provided for various types ofhydroprocessing of feeds or effluents. Examples of hydroprocessing caninclude, but are not limited to, one or more of hydrotreating,hydrocracking, catalytic dewaxing, and hydrofinishing/aromaticsaturation. Such hydroprocessing conditions can be controlled to havedesired values for the conditions (e.g., temperature, pressure, LHSV,treat gas rate) by using at least one controller, such as a plurality ofcontrollers, to control one or more of the hydroprocessing conditions.In some aspects, for a given type of hydroprocessing, at least onecontroller can be associated with each type of hydroprocessingcondition. In some aspects, one or more of the hydroprocessingconditions can be controlled by an associated controller. Examples ofstructures that can be controlled by a controller can include, but arenot limited to, valves that control a flow rate, a pressure, or acombination thereof; heat exchangers and/or heaters that control atemperature, and one or more flow meters and one or more associatedvalves that control relative flow rates of at least two flows. Suchcontrollers can optionally include a controller feedback loop includingat least a processor, a detector for detecting a value of a controlvariable (e.g., temperature, pressure, flow rate, and a processor outputfor controlling the value of a manipulated variable (e.g., changing theposition of a valve, increasing or decreasing the duty cycle and/ortemperature for a heater). Optionally, at least one hydroprocessingcondition for a given type of hydroprocessing may not have an associatedcontroller.

In this discussion, unless otherwise specified a lubricant boiling rangefraction corresponds to a fraction having an initial boiling point oralternatively a T5 boiling point of at least about 370° C. (˜700° F.). Adistillate fuel boiling range fraction, such as a diesel productfraction, corresponds to a fraction having a boiling range from about193° C. (˜375° F.) to about 370° C. (˜700° F.). Thus, distillate fuelboiling range fractions (such as distillate fuel product fractions) canhave initial boiling points (or alternatively T5 boiling points) of atleast about 193° C. and final boiling points (or alternatively T95boiling points) of about 370° C. or less. A naphtha boiling rangefraction corresponds to a fraction having a boiling range from about 36°C. (122° F.) to about 193° C. (375° F.) to about 370° C. (˜700° F.).Thus, naphtha fuel product fractions can have initial boiling points (oralternatively T5 boiling points) of at least about 36° C. and finalboiling points (or alternatively T95 boiling points) of about 193° C. orless. It is noted that 36° C. roughly corresponds to a boiling point forthe various isomers of a C5 alkane. A fuels boiling range fraction cancorrespond to a distillate fuel boiling range fraction, a naphthaboiling range fraction, or a fraction that includes both distillate fuelboiling range and naphtha boiling range components. Light ends aredefined as products with boiling points below about 36° C., whichinclude various C1-C4 compounds. When determining a boiling point or aboiling range for a feed or product fraction, an appropriate ASTM testmethod can be used, such as the procedures described in ASTM D2887,D2892, and/or D86. Preferably, ASTM D2887 should be used unless a sampleis not appropriate for characterization based on ASTM D2887. Forexample, for samples that will not completely elute from achromatographic column, ASTM D7169 can be used.

Feedstocks

In various aspects, at least a portion of a feedstock for processing asdescribed herein can correspond to a vacuum resid fraction or anothertype 950° F.+ (510° C.+) or 1000° F.+ (538° C.+) fraction. Anotherexample of a method for forming a 950° F.+ (510° C.+) or 1000° F.+ (538°C.+) fraction is to perform a high temperature flash separation. The950° F.+ (510° C.+) or 1000° F.+(538° C.+) fraction formed from the hightemperature flash can be processed in a manner similar to a vacuumresid.

A vacuum resid fraction or a 950° F.+ (510° C.+) fraction formed byanother process (such as a flash fractionation bottoms or a bitumenfraction) can be deasphalted at low severity to form a deasphalted oil.Optionally, the feedstock can also include a portion of a conventionalfeed for lubricant base stock production, such as a vacuum gas oil.

A vacuum resid (or other 510° C.+) fraction can correspond to a fractionwith a T5 distillation point (ASTM D2892, or ASTM D7169 if the fractionwill not completely elute from a chromatographic system) of at leastabout 900° F. (482° C.), or at least 950° F. (510° C.), or at least1000° F. (538° C.). Alternatively, a vacuum resid fraction can becharacterized based on a T10 distillation point (ASTM D2892/D7169) of atleast about 900° F. (482° C.), or at least 950° F. (510° C.), or atleast 1000° F. (538° C.).

Resid (or other 510° C.+) fractions can be high in metals. For example,a resid fraction can be high in total nickel, vanadium and ironcontents. In an aspect, a resid fraction can contain at least 0.00005grams of Ni/V/Fe (50 wppm) or at least 0.0002 grams of Ni/V/Fe (200wppm) per gram of resid, on a total elemental basis of nickel, vanadiumand iron. In other aspects, the heavy oil can contain at least 500 wppmof nickel, vanadium, and iron, such as up to 1000 wppm or more.

Contaminants such as nitrogen and sulfur are typically found in resid(or other 510° C.+) fractions, often in organically-bound form. Nitrogencontent can range from about 50 wppm to about 10,000 wppm elementalnitrogen or more, based on total weight of the resid fraction. Sulfurcontent can range from 500 wppm to 100,000 wppm elemental sulfur ormore, based on total weight of the resid fraction, or from 1000 wppm to50,000 wppm, or from 1000 wppm to 30,000 wppm.

Still another method for characterizing a resid (or other 510° C.+)fraction is based on the Conradson carbon residue (CCR) of thefeedstock. The Conradson carbon residue of a resid fraction can be atleast about 5 wt %, such as at least about 10 wt % or at least about 20wt %. Additionally or alternately, the Conradson carbon residue of aresid fraction can be about 50 wt %, or less, such as about 40 wt % orless or about 30 wt % or less.

In some aspects, a vacuum gas oil fraction can be co-processed with adeasphalted oil. The vacuum gas oil can be combined with the deasphaltedoil in various amounts ranging from parts (by weight) deasphalted oil to1 part vacuum gas oil (i.e., 20:1) to 1 part deasphalted oil to 1 partvacuum gas oil. In some aspects, the ratio of deasphalted oil to vacuumgas oil can be at least 1:1 by weight, or at least 1.5:1, or at least2:1. Typical (vacuum) gas oil fractions can include, for example,fractions with a T5 distillation point to T95 distillation point of 650°F. (343° C.)-1050° F. (566° C.), or 650° F. (343° C.)-1000° F. (538°C.), or 650° F. (343° C.)-950° F. (510° C.), or 650° F. (343° C.)-900°F. (482° C.), or ˜700° F. (370° C.)-1050° F. (566° C.), or ˜700° F.(370° C.)-1000° F. (538° C.), or ˜700° F. (370° C.)-950° F. (510° C.),or ˜700° F. (370° C.)-900° F. (482° C.), or 750° F. (399° C.)-1050° F.(566° C.), or 750° F. (399° C.)-1000° F. (538° C.), or 750° F. (399°C.)-950° F. (510° C.), or 750° F. (399° C.)-900° F. (482° C.). Forexample a suitable vacuum gas oil fraction can have a T5 distillationpoint of at least 343° C. and a T95 distillation point of 566° C. orless; or a T10 distillation point of at least 343° C. and a T90distillation point of 566° C. or less; or a T5 distillation point of atleast 370° C. and a T95 distillation point of 566° C. or less; or a T5distillation point of at least 343° C. and a T95 distillation point of538° C. or less.

Solvent Deasphalting

Solvent deasphalting is a solvent extraction process. In some aspects,suitable solvents for methods as described herein include alkanes orother hydrocarbons (such as alkenes) containing 4 to 7 carbons permolecule. Examples of suitable solvents include n-butane, isobutane,n-pentane, C₄₊ alkanes. C₅₊ alkanes, C₄₊ hydrocarbons, and C₅₊hydrocarbons. In other aspects, suitable solvents can include C₃hydrocarbons, such as propane. In such other aspects, examples ofsuitable solvents include propane, n-butane, isobutane, n-pentane, C₃₊alkanes, C₄₊ alkanes, C₅₊ alkanes, C₃₊ hydrocarbons, C₄₊ hydrocarbons,and C₅₊ hydrocarbons

In this discussion, a solvent comprising C_(n) (hydrocarbons) is definedas a solvent composed of at least 80 wt % of alkanes (hydrocarbons)having n carbon atoms, or at least 85 wt %, or at least 90% wt %, or atleast 95 wt %, or at least 98 wt %. Similarly, a solvent comprisingC_(n+) (hydrocarbons) is defined as a solvent composed of at least 80 wt% of alkanes (hydrocarbons) having n or more carbon atoms, or at least85 wt %, or at least 90 wt %, or at least 95 wt %, or at least 98 wt %.

In this discussion, a solvent comprising C_(n) alkanes (hydrocarbons) isdefined to include the situation where the solvent corresponds to asingle alkane (hydrocarbon) containing n carbon atoms (for example, n=3,4, 5, 6, 7) as well as the situations where the solvent is composed of amixture of alkanes (hydrocarbons) containing n carbon atoms. Similarly,a solvent comprising C_(n+) alkanes (hydrocarbons) is defined to includethe situation where the solvent corresponds to a single alkane(hydrocarbon) containing n or more carbon atoms (for example, n=3, 4, 5,6, 7) as well as the situations where the solvent corresponds to amixture of alkanes (hydrocarbons) containing n or more carbon atoms.Thus, a solvent comprising C₄₊ alkanes can correspond to a solventincluding n-butane; a solvent include n-butane and isobutane; a solventcorresponding to a mixture of one or more butane isomers and one or morepentane isomers; or any other convenient combination of alkanescontaining 4 or more carbon atoms. Similarly, a solvent comprising C₅₊alkanes (hydrocarbons) is defined to include a solvent corresponding toa single alkane (hydrocarbon) or a solvent corresponding to a mixture ofalkanes (hydrocarbons) that contain 5 or more carbon atoms.Alternatively, other types of solvents may also be suitable, such assupercritical fluids. In various aspects, the solvent for solventdeasphalting can consist essentially of hydrocarbons, so that at least98 wt % or at least 99 wt % of the solvent corresponds to compoundscontaining only carbon and hydrogen. In aspects where the deasphaltingsolvent corresponds to a C₄₊ deasphalting solvent, the C₄₊ deasphaltingsolvent can include less than 15 wt % propane and/or other C₃hydrocarbons, or less than 10 wt %, or less than 5 wt %, or the C₄₊deasphalting solvent can be substantially free of propane and/or otherC₃ hydrocarbons (less than 1 wt %). In aspects where the deasphaltingsolvent corresponds to a C₅₊ deasphalting solvent, the C₅₊ deasphaltingsolvent can include less than 15 wt % propane, butane and/or other C₃-C₄hydrocarbons, or less than 10 wt %, or less than 5 wt %, or the C₅₊deasphalting solvent can be substantially free of propane, butane,and/or other C₃-C₄ hydrocarbons (less than 1 wt %). In aspects where thedeasphalting solvent corresponds to a C₃₊ deasphalting solvent, the C₅₊deasphalting solvent can include less than 10 wt % ethane and/or otherC₂ hydrocarbons, or less than 5 wt %, or the C₃₊ deasphalting solventcan be substantially free of ethane and/or other C₂ hydrocarbons (lessthan 1 wt %).

Deasphalting of heavy hydrocarbons, such as vacuum resids, is known inthe art and practiced commercially. A deasphalting process typicallycorresponds to contacting a heavy hydrocarbon with an alkane solvent(propane, butane, pentane, hexane, heptane etc and their isomers),either in pure form or as mixtures, to produce two types of productstreams. One type of product stream can be a deasphalted oil extractedby the alkane, which is further separated to produce deasphalted oilstream. A second type of product stream can be a residual portion of thefeed not soluble in the solvent, often referred to as rock or asphaltenefraction. The deasphalted oil fraction can be further processed intomake fuels or lubricants. The rock fraction can be further used as blendcomponent to produce asphalt, fuel oil, and/or other products. The rockfraction can also be used as feed to gasification processes such aspartial oxidation, fluid bed combustion or coking processes. The rockcan be delivered to these processes as a liquid (with or withoutadditional components) or solid (either as pellets or lumps).

During solvent deasphalting, a resid boiling range feed (optionally alsoincluding a portion of a vacuum gas oil feed) can be mixed with asolvent. Portions of the feed that are soluble in the solvent are thenextracted, leaving behind a residue with little or no solubility in thesolvent. The portion of the deasphalted feedstock that is extracted withthe solvent is often referred to as deasphalted oil. Typical solventdeasphalting conditions include mixing a feedstock fraction with asolvent in a weight ratio of from about 1:2 to about 1:10, such as about1:8 or less. Typical solvent deasphalting temperatures range from 40° C.to 200° C., or 40° C. to 150° C., depending on the nature of the feedand the solvent. The pressure during solvent deasphalting can be fromabout 50 psig (345 kPag) to about 500 psig (3447 kPag).

It is noted that the above solvent deasphalting conditions represent ageneral range, and the conditions will vary depending on the feed. Forexample, under typical deasphalting conditions, increasing thetemperature can tend to reduce the yield while increasing the quality ofthe resulting deasphalted oil. Under typical deasphalting conditions,increasing the molecular weight of the solvent can tend to increase theyield while reducing the quality of the resulting deasphalted oil, asadditional compounds within a resid fraction may be soluble in a solventcomposed of higher molecular weight hydrocarbons. Under typicaldeasphalting conditions, increasing the amount of solvent can tend toincrease the yield of the resulting deasphalted oil. As understood bythose of skill in the art, the conditions for a particular feed can beselected based on the resulting yield of deasphalted oil from solventdeasphalting. In aspects where a C₃ deasphalting solvent is used, theyield from solvent deasphalting can be 40 wt % or less. In some aspects,C₄ deasphalting can be performed with a yield of deasphalted oil of 50wt % or less, or 40 wt % or less. In various aspects, the yield ofdeasphalted oil from solvent deasphalting with a C₄₊ solvent can be atleast 50 wt % relative to the weight of the feed to deasphalting, or atleast 55 wt %, or at least 60 wt % or at least 65 wt %, or at least 70wt %. In aspects where the feed to deasphalting includes a vacuum gasoil portion, the yield from solvent deasphalting can be characterizedbased on a yield by weight of a 950° F.+ (510° C.) portion of thedeasphalted oil relative to the weight of a 510° C.+ portion of thefeed. In such aspects where a C₄₊ solvent is used, the yield of 510° C.+deasphalted oil from solvent deasphalting can be at least 40 wt %relative to the weight of the 510° C.+ portion of the feed todeasphalting, or at least 50 wt %, or at least 55 wt %, or at least 60wt %, or at least 65 wt %, or at least 70 wt %. In such aspects where aC₄₊ solvent is used, the yield of 510° C.+ deasphalted oil from solventdeasphalting can be 50 wt % or less relative to the weight of the 510°C.+ portion of the feed to deasphalting, or 40 wt % or less, or 35 wt %or less.

Hydrotreating and Hydrocracking

After deasphalting, the deasphalted oil (and any additional fractionscombined with the deasphalted oil) can undergo further processing toform lubricant base stocks. This can include hydrotreatment and/orhydrocracking to remove heteroatoms to desired levels, reduce ConradsonCarbon content, and/or provide viscosity index (VI) uplift. Depending onthe aspect, a deasphalted oil can be hydroprocessed by hydrotreating,hydrocracking, or hydrotreating and hydrocracking.

The deasphalted oil can be hydrotreated and/or hydrocracked with littleor no solvent extraction being performed prior to and/or after thedeasphalting. As a result, the deasphalted oil feed for hydrotreatmentand/or hydrocracking can have a substantial aromatics content. Invarious aspects, the aromatics content of the deasphalted oil feed canbe at least 50 wt %, or at least 55 wt %, or at least 60 wt %, or atleast 65 wt %, or at least 70 wt %, or at least 75 wt %, such as up to90 wt % or more. Additionally or alternately, the saturates content ofthe deasphalted oil feed can be 50 wt % or less, or 45 wt % or less, or40 wt % or less, or 35 wt % or less, or 30 wt % or less, or 25 wt % orless, such as down to 10 wt % or less. In this discussion and the claimsbelow, the aromatics content and/or the saturates content of a fractioncan be determined based on ASTM D7419.

The reaction conditions during demetallization and/or hydrotreatmentand/or hydrocracking of the deasphalted oil (and optional vacuum gas oilco-feed) can be selected to generate a desired level of conversion of afeed. Any convenient type of reactor, such as fixed bed (for exampletrickle bed) reactors can be used. Conversion of the feed can be definedin terms of conversion of molecules that boil above a temperaturethreshold to molecules below that threshold. The conversion temperaturecan be any convenient temperature, such as −700° F. (370° C.) or 1050°F. (566° C.). The amount of conversion can correspond to the totalconversion of molecules within the combined hydrotreatment andhydrocracking stages for the deasphalted oil. Suitable amounts ofconversion of molecules boiling above 1050° F. (566° C.) to moleculesboiling below 566° C. include 30 wt % to 90 wt % conversion relative to566° C., or 30 wt % to 80 wt %, or 30 wt % to 70 wt %, or 40 wt % to 90wt %, or 40 wt % to 80 wt %, or 40 wt % to 70 wt %, or 50 wt % to 90 wt%, or 50 wt % to 80 wt %, or 50 wt % to 70 wt %. In particular, theamount of conversion relative to 566° C. can be 30 wt % to 90 wt %, or30 wt % to 70 wt %, or 50 wt % to 90 wt %. Additionally or alternately,suitable amounts of conversion of molecules boiling above −700° F. (370°C.) to molecules boiling below 370° C. include 10 wt % to 70 wt %conversion relative to 370° C., or 10 wt % to 60 wt % or 10 wt % to 50wt %, or 20 wt % to 70 wt %, or 20 wt % to 60 wt %, or 20 wt % to 50 wt%, or 30 wt % to 70 wt %, or 30 wt % to 60 wt %, or 30 wt % to 50 wt %.In particular, the amount of conversion relative to 370° C. can be 10 wt% to 70 wt %, or 20 wt % to 50 wt %, or 30 wt % to 60 wt %.

The hydroprocessed deasphalted oil can also be characterized based onthe product quality. After hydroprocessing (hydrotreating and/orhydrocracking), the hydroprocessed deasphalted oil can have a sulfurcontent of 200 wppm or less, or 100 wppm or less, or 50 wppm or less(such as down to ˜0 wppm). Additionally or alternately, thehydroprocessed deasphalted oil can have a nitrogen content of 200 wppmor less, or 100 wppm or less, or 50 wppm or less (such as down to ˜0wppm). Additionally or alternately, the hydroprocessed deasphalted oilcan have a Conradson Carbon residue content of 1.5 wt % or less, or 1.0wt % or less, or 0.7 wt % or less, or 0.1 wt % or less, or 0.02 wt % orless (such as down to ˜0 wt %). Conradson Carbon residue content can bedetermined according to ASTM D4530.

In various aspects, a feed can initially be exposed to a demetallizationcatalyst prior to exposing the feed to a hydrotreating catalyst.Deasphalted oils can have metals concentrations (Ni+V+Fe) on the orderof 10-100 wppm. Exposing a conventional hydrotreating catalyst to a feedhaving a metals content of 10 wppm or more can lead to catalystdeactivation at a faster rate than may desirable in a commercialsetting. Exposing a metal containing feed to a demetallization catalystprior to the hydrotreating catalyst can allow at least a portion of themetals to be removed by the demetallization catalyst, which can reduceor minimize the deactivation of the hydrotreating catalyst and/or othersubsequent catalysts in the process flow. Commercially availabledemetallization catalysts can be suitable, such as large pore amorphousoxide catalysts that may optionally include Group VI and/or Group VIIInon-noble metals to provide some hydrogenation activity.

In various aspects, the deasphalted oil can be exposed to ahydrotreating catalyst under effective hydrotreating conditions. Thecatalysts used can include conventional hydroprocessing catalysts, suchas those comprising at least one Group VIII non-noble metal (Columns8-10 of IUPAC periodic table), preferably Fe, Co, and/or Ni, such as Coand/or Ni; and at least one Group VI metal (Column 6 of IUPAC periodictable), preferably Mo and/or W. Such hydroprocessing catalystsoptionally include transition metal sulfides that are impregnated ordispersed on a refractory support or carrier such as alumina and/orsilica. The support or carrier itself typically has nosignificant/measurable catalytic activity. Substantially carrier- orsupport-free catalysts, commonly referred to as bulk catalysts,generally have higher volumetric activities than their supportedcounterparts.

The catalysts can either be in bulk form or in supported form. Inaddition to alumina and/or silica, other suitable support/carriermaterials can include, but are not limited to, zeolites, titania,silica-titania, and titania-alumina. Suitable aluminas are porousaluminas such as gamma or eta having average pore sizes from 50 to 200Å, or 75 to 150 Å; a surface area from 100 to 300 m²/g, or 150 to 250m²/g; and a pore volume of from 0.25 to 1.0 cm³/g, or 0.35 to 0.8 cm³/g.More generally, any convenient size, shape, and/or pore sizedistribution for a catalyst suitable for hydrotreatment of a distillate(including lubricant base stock) boiling range feed in a conventionalmanner may be used. Preferably, the support or carrier material is anamorphous support, such as a refractory oxide. Preferably, the supportor carrier material can be free or substantially free of the presence ofmolecular sieve, where substantially free of molecular sieve is definedas having a content of molecular sieve of less than about 0.01 wt %.

The at least one Group VIII non-noble metal, in oxide form, cantypically be present in an amount ranging from about 2 wt % to about 40wt %, preferably from about 4 wt % to about 15 wt %. The at least oneGroup VI metal, in oxide form, can typically be present in an amountranging from about 2 wt % to about 70 wt %, preferably for supportedcatalysts from about 6 wt % to about 40 wt % or from about 10 wt % toabout 30 wt %. These weight percents are based on the total weight ofthe catalyst. Suitable metal catalysts include cobalt/molybdenum (1-10%Co as oxide, 10-40% Mo as oxide), nickel/molybdenum (1-10% Ni as oxide,10-40% Co as oxide), or nickel/tungsten (1-10% Ni as oxide, 10-40% W asoxide) on alumina, silica, silica-alumina, or titania.

The hydrotreatment is carried out in the presence of hydrogen. Ahydrogen stream is, therefore, fed or injected into a vessel or reactionzone or hydroprocessing zone in which the hydroprocessing catalyst islocated. Hydrogen, which is contained in a hydrogen “treat gas,” isprovided to the reaction zone. Treat gas, as referred to in thisinvention, can be either pure hydrogen or a hydrogen-containing gas,which is a gas stream containing hydrogen in an amount that issufficient for the intended reaction(s), optionally including one ormore other gasses (e.g., nitrogen and light hydrocarbons such asmethane). The treat gas stream introduced into a reaction stage willpreferably contain at least about 50 vol. % and more preferably at leastabout 75 vol. % hydrogen. Optionally, the hydrogen treat gas can besubstantially free (less than 1 vol %) of impurities such as H₂S and NHand/or such impurities can be substantially removed from a treat gasprior to use.

Hydrogen can be supplied at a rate of from about 100 SCF/B (standardcubic feet of hydrogen per barrel of feed) (17 Nm³/m³) to about 10000SCF/B (1700 Nm³/m³). Preferably, the hydrogen is provided in a range offrom about 200 SCF/B (34 Nm³/m³) to about 2500 SCF/B (420 Nm³/m³).Hydrogen can be supplied co-currently with the input feed to thehydrotreatment reactor and/or reaction zone or separately via a separategas conduit to the hydrotreatment zone.

Hydrotreating conditions can include temperatures of 200° C. to 450° C.,or 315° C. to 425° C.; pressures of 250 psig (1.8 MPag) to 5000 psig(34.6 MPag) or 300 psig (2.1 MPag) to 3000 psig (20.8 MPag); liquidhourly space velocities (LHSV) of 0.1 hr⁻¹ to 10 hr⁻¹; and hydrogentreat rates of 200 scf/B (35.6 m³/m³) to 10,000 scf/B (1781 m³/m³), or500 (89 m³/m³) to 10,000 scf/B (1781 m³/m³).

In various aspects, the deasphalted oil can be exposed to ahydrocracking catalyst under effective hydrocracking conditions.Hydrocracking catalysts typically contain sulfided base metals on acidicsupports, such as amorphous silica alumina, cracking zeolites such asUSY, or acidified alumina. Often these acidic supports are mixed orbound with other metal oxides such as alumina, titania or silica.Examples of suitable acidic supports include acidic molecular sieves,such as zeolites or silicoaluminophophates. One example of suitablezeolite is USY, such as a USY zeolite with cell size of 24.30 Angstromsor less. Additionally or alternately, the catalyst can be a low aciditymolecular sieve, such as a USY zeolite with a Si to Al ratio of at leastabout 20, and preferably at least about 40 or 50. ZSM-48, such as ZSM-48with a SiO₂ to Al₂O₃ ratio of about 110 or less, such as about 90 orless, is another example of a potentially suitable hydrocrackingcatalyst. Still another option is to use a combination of USY andZSM-48. Still other options include using one or more of zeolite Beta,ZSM-5, ZSM-35, or ZSM-23, either alone or in combination with a USYcatalyst. Non-limiting examples of metals for hydrocracking catalystsinclude metals or combinations of metals that include at least one GroupVIII metal, such as nickel, nickel-cobalt-molybdenum, cobalt-molybdenum,nickel-tungsten, nickel-molybdenum, and/or nickel-molybdenum-tungsten.Additionally or alternately, hydrocracking catalysts with noble metalscan also be used. Non-limiting examples of noble metal catalysts includethose based on platinum and/or palladium. Support materials which may beused for both the noble and non-noble metal catalysts can comprise arefractory oxide material such as alumina, silica, alumina-silica,kieselguhr, diatomaceous earth, magnesia, zirconia, or combinationsthereof, with alumina, silica, alumina-silica being the most common (andpreferred, in one embodiment).

When only one hydrogenation metal is present on a hydrocrackingcatalyst, the amount of that hydrogenation metal can be at least about0.1 wt % based on the total weight of the catalyst, for example at leastabout 0.5 wt % or at least about 0.6 wt %. Additionally or alternatelywhen only one hydrogenation metal is present, the amount of thathydrogenation metal can be about 5.0 wt % or less based on the totalweight of the catalyst, for example about 3.5 wt % or less, about 2.5 wt% or less, about 1.5 wt % or less, about 1.0 wt % or less, about 0.9 wt% or less, about 0.75 wt % or less, or about 0.6 wt % or less. Furtheradditionally or alternately when more than one hydrogenation metal ispresent, the collective amount of hydrogenation metals can be at leastabout 0.1 wt % based on the total weight of the catalyst, for example atleast about 0.25 wt %, at least about 0.5 wt %, at least about 0.6 wt %,at least about 0.75 wt %, or at least about 1 wt %. Still furtheradditionally or alternately when more than one hydrogenation metal ispresent, the collective amount of hydrogenation metals can be about 35wt % or less based on the total weight of the catalyst, for exampleabout 30 wt % or less, about 25 wt % or less, about 20 wt % or less,about 15 wt % or less, about 10 wt % or less, or about 5 wt % or less.In embodiments wherein the supported metal comprises a noble metal, theamount of noble metal(s) is typically less than about 2 wt %, forexample less than about 1 wt %, about 0.9 wt % or less, about 0.75 wt %or less, or about 0.6 wt % or less. It is noted that hydrocracking undersour conditions is typically performed using a base metal (or metals) asthe hydrogenation metal.

In various aspects, the conditions selected for hydrocracking forlubricant base stock production can depend on the desired level ofconversion, the level of contaminants in the input feed to thehydrocracking stage, and potentially other factors. For example,hydrocracking conditions in a single stage, or in the first stage and/orthe second stage of a multi-stage system, can be selected to achieve adesired level of conversion in the reaction system. Hydrocrackingconditions can be referred to as sour conditions or sweet conditions,depending on the level of sulfur and/or nitrogen present within a feed.For example, a feed with 100 wppm or less of sulfur and 50 wppm or lessof nitrogen, preferably less than 25 wppm sulfur and/or less than 10wppm of nitrogen, represent a feed for hydrocracking under sweetconditions. In various aspects, hydrocracking can be performed on athermally cracked resid, such as a deasphalted oil derived from athermally cracked resid. In some aspects, such as aspects where anoptional hydrotreating step is used prior to hydrocracking, thethermally cracked resid may correspond to a sweet feed. In otheraspects, the thermally cracked resid may represent a feed forhydrocracking under sour conditions.

A hydrocracking process under sour conditions can be carried out attemperatures of about 550° F. (288° C.) to about 840° F. (449° C.),hydrogen partial pressures of from about 1500 psig to about 5000 psig(10.3 MPag to 34.6 MPag), liquid hourly space velocities of from 0.05h⁻¹ to 10 h⁻¹, and hydrogen treat gas rates of from 35.6 m³/m³ to 1781m³/m³ (200 SCF/B to 10,000 SCF/B). In other embodiments, the conditionscan include temperatures in the range of about 600° F. (343° C.) toabout 815° F. (435° C.), hydrogen partial pressures of from about 1500psig to about 3000 psig (10.3 MPag-20.9 MPag), and hydrogen treat gasrates of from about 213 m³/m³ to about 1068 m³/m³ (1200 SCF/B to 6000SCF/B). The LHSV can be from about 0.25 h⁻¹ to about 50 h⁻¹, or fromabout 0.5 h⁻¹ to about 20 h⁻¹, preferably from about 1.0 h⁻¹ to about4.0 h⁻¹.

In some aspects, a portion of the hydrocracking catalyst can becontained in a second reactor stage. In such aspects, a first reactionstage of the hydroprocessing reaction system can include one or morehydrotreating and/or hydrocracking catalysts. The conditions in thefirst reaction stage can be suitable for reducing the sulfur and/ornitrogen content of the feedstock. A separator can then be used inbetween the first and second stages of the reaction system to remove gasphase sulfur and nitrogen contaminants. One option for the separator isto simply perform a gas-liquid separation to remove contaminant. Anotheroption is to use a separator such as a flash separator that can performa separation at a higher temperature. Such a high temperature separatorcan be used, for example, to separate the feed into a portion boilingbelow a temperature cut point, such as about 350° F. (177° C.) or about400° F. (204° C.), and a portion boiling above the temperature cutpoint. In this type of separation, the naphtha boiling range portion ofthe effluent from the first reaction stage can also be removed, thusreducing the volume of effluent that is processed in the second or othersubsequent stages. Of course, any low boiling contaminants in theeffluent from the first stage would also be separated into the portionboiling below the temperature cut point. If sufficient contaminantremoval is performed in the first stage, the second stage can beoperated as a “sweet” or low contaminant stage.

Still another option can be to use a separator between the first andsecond stages of the hydroprocessing reaction system that can alsoperform at least a partial fractionation of the effluent from the firststage. In this type of aspect, the effluent from the firsthydroprocessing stage can be separated into at least a portion boilingbelow the distillate (such as diesel) fuel range, a portion boiling inthe distillate fuel range, and a portion boiling above the distillatefuel range. The distillate fuel range can be defined based on aconventional diesel boiling range, such as having a lower end cut pointtemperature of at least about 350° F. (177° C.) or at least about 400°F. (204° C.) to having an upper end cut point temperature of about 700°F. (371° C.) or less or 650° F. (343° C.) or less. Optionally, thedistillate fuel range can be extended to include additional kerosene,such as by selecting a lower end cut point temperature of at least about300° F. (149° C.).

In aspects where the inter-stage separator is also used to produce adistillate fuel fraction, the portion boiling below the distillate fuelfraction includes, naphtha boiling range molecules, light ends, andcontaminants such as H₂S. These different products can be separated fromeach other in any convenient manner. Similarly, one or more distillatefuel fractions can be formed, if desired, from the distillate boilingrange fraction. The portion boiling above the distillate fuel rangerepresents the potential lubricant base stocks. In such aspects, theportion boiling above the distillate fuel range is subjected to furtherhydroprocessing in a second hydroprocessing stage.

A hydrocracking process under sweet conditions can be performed underconditions similar to those used for a sour hydrocracking process, orthe conditions can be different. In an embodiment, the conditions in asweet hydrocracking stage can have less severe conditions than ahydrocracking process in a sour stage. Suitable hydrocracking conditionsfor a non-sour stage can include, but are not limited to, conditionssimilar to a first or sour stage. Suitable hydrocracking conditions caninclude temperatures of about 500° F. (260° C.) to about 840° F. (449°C.), hydrogen partial pressures of from about 1500 psig to about 5000psig (10.3 MPag to 34.6 MPag), liquid hourly space velocities of from0.05 h⁻¹ to 10 h⁻¹, and hydrogen treat gas rates of from 35.6 m³/m³ to1781 m³/m³ (200 SCF/B to 10,000 SCF/B). In other embodiments, theconditions can include temperatures in the range of about 600° F. (343°C.) to about 815° F. (435° C.), hydrogen partial pressures of from about1500 psig to about 3000 psig (10.3 MPag-20.9 MPag), and hydrogen treatgas rates of from about 213 m³/m³ to about 1068 m³/m³ (1200 SCF/B to6000 SCF/B). The LHSV can be from about 0.25 h⁻¹ to about 50 h⁻¹, orfrom about 0.5 h⁻¹ to about 20 h⁻¹, preferably from about 1.0 h⁻¹ toabout 4.0 h⁻¹.

In still another aspect, the same conditions can be used forhydrotreating and hydrocracking beds or stages, such as usinghydrotreating conditions for both or using hydrocracking conditions forboth. In yet another embodiment, the pressure for the hydrotreating andhydrocracking beds or stages can be the same.

In yet another aspect, a hydroprocessing reaction system may includemore than one hydrocracking stage. If multiple hydrocracking stages arepresent, at least one hydrocracking stage can have effectivehydrocracking conditions as described above, including a hydrogenpartial pressure of at least about 1500 psig (10.3 MPag). In such anaspect, other hydrocracking processes can be performed under conditionsthat may include lower hydrogen partial pressures. Suitablehydrocracking conditions for an additional hydrocracking stage caninclude, but are not limited to, temperatures of about 500° F. (260° C.)to about 840° F. (449° C.), hydrogen partial pressures of from about 250psig to about 5000 psig (1.8 MPag to 34.6 MPag), liquid hourly spacevelocities of from 0.05 h⁻¹ to 10 h⁻¹, and hydrogen treat gas rates offrom 35.6 m³/m³ to 1781 m³/m³ (200 SCF/B to 10,000 SCF/B). In otherembodiments, the conditions for an additional hydrocracking stage caninclude temperatures in the range of about 600° F. (343° C.) to about815° F. (435° C.), hydrogen partial pressures of from about 500 psig toabout 3000 psig (3.5 MPag-20.9 MPag), and hydrogen treat gas rates offrom about 213 m³/m³ to about 1068 m³/m³ (1200 SCF/B to 6000 SCF/B). TheLHSV can be from about 0.25 h⁻¹ to about 50 h⁻¹, or from about 0.5 h⁻¹to about 20 h⁻¹, and preferably from about 1.0 h⁻¹ to about 4.0 h⁻¹.

Hydroprocessed Effluent—Solvent Dewaxing to Form Group I Bright Stock

The hydroprocessed deasphalted oil (optionally including hydroprocessedvacuum gas oil) can be separated to form one or more fuel boiling rangefractions (such as naphtha or distillate fuel boiling range fractions)and at least one lubricant base stock boiling range fraction. Thelubricant base stock boiling range fraction(s) can then be solventdewaxed to produce a lubricant base stock product with a reduced (oreliminated) tendency to form haze. Lubricant base stocks (includingbright stock) formed by hydroprocessing a deasphalted oil and thensolvent dewaxing the hydroprocessed effluent can tend to be Group I basestocks due to having an aromatics content of at least 10 wt %.

Solvent dewaxing typically involves mixing a feed with chilled dewaxingsolvent to form an oil-solvent solution. Precipitated wax is thereafterseparated by, for example, filtration. The temperature and solvent areselected so that the oil is dissolved by the chilled solvent while thewax is precipitated.

An example of a suitable solvent dewaxing process involves the use of acooling tower where solvent is prechilled and added incrementally atseveral points along the height of the cooling tower. The oil-solventmixture is agitated during the chilling step to permit substantiallyinstantaneous mixing of the prechilled solvent with the oil. Theprechilled solvent is added incrementally along the length of thecooling tower so as to maintain an average chilling rate at or below 10°F. per minute, usually between about 1 to about 5° F. per minute. Thefinal temperature of the oil-solvent/precipitated wax mixture in thecooling tower will usually be between 0 and 50° F. (−17.8 to 10° C.).The mixture may then be sent to a scraped surface chiller to separateprecipitated wax from the mixture.

Representative dewaxing solvents are aliphatic ketones having 3-6 carbonatoms such as methyl ethyl ketone and methyl isobutyl ketone, lowmolecular weight hydrocarbons such as propane and butane, and mixturesthereof. The solvents may be mixed with other solvents such as benzene,toluene or xylene.

In general, the amount of solvent added will be sufficient to provide aliquid/solid weight ratio between the range of 5/1 and 20/1 at thedewaxing temperature and a solvent/oil volume ratio between 1.5/1 to5/1. The solvent dewaxed oil can be dewaxed to a pour point of −6° C. orless, or −10° C. or less, or −15° C. or less, depending on the nature ofthe target lubricant base stock product. Additionally or alternately,the solvent dewaxed oil can be dewaxed to a cloud point of −2° C. orless, or −5° C. or less, or −10° C. or less, depending on the nature ofthe target lubricant base stock product. The resulting solvent dewaxedoil can be suitable for use in forming one or more types of Group I basestocks. Preferably, a bright stock formed from the solvent dewaxed oilcan have a cloud point below −5° C. The resulting solvent dewaxed oilcan have a viscosity index of at least 90, or at least 95, or at least100. Preferably, at least 10 wt % of the resulting solvent dewaxed oil(or at least 20 wt %, or at least 30 wt %) can correspond to a Group Ibright stock having a kinematic viscosity at 100° C. of at least 15 cSt,or at least 20 cSt, or at least 25 cSt, such as up to 50 cSt or more.

In some aspects, the reduced or eliminated tendency to form haze for thelubricant base stocks formed from the solvent dewaxed oil can bedemonstrated by a reduced or minimized difference between the cloudpoint temperature and pour point temperature for the lubricant basestocks. In various aspects, the difference between the cloud point andpour point for the resulting solvent dewaxed oil and/or for one or morelubricant base stocks, including one or more bright stocks, formed fromthe solvent dewaxed oil, can be 22° C. or less, or 20° C. or less, or15° C. or less, or 10° C. or less, or 8° C. or less, or 5° C. or less.Additionally or alternately, a reduced or minimized tendency for abright stock to form haze over time can correspond to a bright stockhaving a cloud point of −10° C. or less, or ˜8° C. or less, or ˜5° C. orless, or ˜2° C. or less.

Additional Hydroprocessing—Catalytic Dewaxing, Hydrofinishing, andOptional Hydrocracking

In some alternative aspects, at least a lubricant boiling range portionof the hydroprocessed deasphalted oil can be exposed to furtherhydroprocessing (including catalytic dewaxing) to form either Group Iand/or Group II base stocks, including Group I and/or Group II brightstock. In some aspects, a first lubricant boiling range portion of thehydroprocessed deasphalted oil can be solvent dewaxed as described abovewhile a second lubricant boiling range portion can be exposed to furtherhydroprocessing. In other aspects, only solvent dewaxing or only furtherhydroprocessing can be used to treat a lubricant boiling range portionof the hydroprocessed deasphalted oil.

Optionally, the further hydroprocessing of the lubricant boiling rangeportion of the hydroprocessed deasphalted oil can also include exposureto hydrocracking conditions before and/or after the exposure to thecatalytic dewaxing conditions. At this point in the process, thehydrocracking can be considered “sweet” hydrocracking, as thehydroprocessed deasphalted oil can have a sulfur content of 200 wppm orless.

Suitable hydrocracking conditions can include exposing the feed to ahydrocracking catalyst as previously described above. Optionally, it canbe preferable to use a USY zeolite with a silica to alumina ratio of atleast 30 and a unit cell size of less than 24.32 Angstroms as thezeolite for the hydrocracking catalyst, in order to improve the VIuplift from hydrocracking and/or to improve the ratio of distillate fuelyield to naphtha fuel yield in the fuels boiling range product.

Suitable hydrocracking conditions can also include temperatures of about500° F. (260° C.) to about 840° F. (449° C.), hydrogen partial pressuresof from about 1500 psig to about 5000 psig (10.3 MPag to 34.6 MPag),liquid hourly space velocities of from 0.05 h⁻¹ to 10 h⁻¹, and hydrogentreat gas rates of from 35.6 m³/m³ to 1781 m³/m³ (200 SCF/B to 10,000SCF/B). In other embodiments, the conditions can include temperatures inthe range of about 600° F. (343° C.) to about 815° F. (435° C.),hydrogen partial pressures of from about 1500 psig to about 3000 psig(10.3 MPag-20.9 MPag), and hydrogen treat gas rates of from about 213m³/m³ to about 1068 m³/m³ (1200 SCF/B to 6000 SCF/B). The LHSV can befrom about 0.25 h⁻¹ to about 50 h⁻¹, or from about 0.5 h⁻¹ to about 20h⁻¹, and preferably from about 1.0 h⁻¹ to about 4.0 h⁻¹.

For catalytic dewaxing, suitable dewaxing catalysts can includemolecular sieves such as crystalline aluminosilicates (zeolites). In anembodiment, the molecular sieve can comprise, consist essentially of, orbe ZSM-22, ZSM-23, ZSM-48. Optionally but preferably, molecular sievesthat are selective for dewaxing by isomerization as opposed to crackingcan be used, such as ZSM-48, ZSM-23, or a combination thereof.Additionally or alternately, the molecular sieve can comprise, consistessentially of, or be a 10-member ring 1-D molecular sieve, such asEU-2, EU-11, ZBM-30, ZSM-48, or ZSM-23. ZSM-48 is most preferred. Notethat a zeolite having the ZSM-23 structure with a silica to aluminaratio of from about 20:1 to about 40:1 can sometimes be referred to asSSZ-32. Optionally but preferably, the dewaxing catalyst can include abinder for the molecular sieve, such as alumina, titania, silica,silica-alumina, zirconia, or a combination thereof, for example aluminaand/or titania or silica and/or zirconia and/or titania.

Preferably, the dewaxing catalysts used in processes according to theinvention are catalysts with a low ratio of silica to alumina. Forexample, for ZSM-48, the ratio of silica to alumina in the zeolite canbe about 100:1 or less, such as about 90:1 or less, or about 75:1 orless, or about 70:1 or less. Additionally or alternately, the ratio ofsilica to alumina in the ZSM-48 can be at least about 50:1, such as atleast about 60:1, or at least about 65:1.

In various embodiments, the catalysts according to the invention furtherinclude a metal hydrogenation component. The metal hydrogenationcomponent is typically a Group VI and/or a Group VIII metal. Preferably,the metal hydrogenation component can be a combination of a non-nobleGroup VIII metal with a Group VI metal. Suitable combinations caninclude Ni, Co. or Fe with Mo or W, preferably Ni with Mo or W.

The metal hydrogenation component may be added to the catalyst in anyconvenient manner. One technique for adding the metal hydrogenationcomponent is by incipient wetness. For example, after combining azeolite and a binder, the combined zeolite and binder can be extrudedinto catalyst particles. These catalyst particles can then be exposed toa solution containing a suitable metal precursor. Alternatively, metalcan be added to the catalyst by ion exchange, where a metal precursor isadded to a mixture of zeolite (or zeolite and binder) prior toextrusion.

The amount of metal in the catalyst can be at least 0.1 wt % based oncatalyst, or at least 0.5 wt %, or at least 1.0 wt %, or at least 2.5 wt%, or at least 5.0 wt %, based on catalyst. The amount of metal in thecatalyst can be 20 wt % or less based on catalyst, or 10 wt % or less,or 5 wt % or less, or 2.5 wt % or less, or 1 wt % or less. Forembodiments where the metal is a combination of a non-noble Group VIIImetal with a Group VI metal, the combined amount of metal can be from0.5 wt % to 20 wt %, or 1 wt % to 15 wt %, or 2.5 wt % to 10 wt %.

The dewaxing catalysts useful in processes according to the inventioncan also include a binder. In some embodiments, the dewaxing catalystsused in process according to the invention are formulated using a lowsurface area binder, a low surface area binder represents a binder witha surface area of 100 m²/g or less, or 80 m²/g or less, or 70 m²/g orless. Additionally or alternately, the binder can have a surface area ofat least about 25 m²/g. The amount of zeolite in a catalyst formulatedusing a binder can be from about 30 wt % zeolite to 90 wt % zeoliterelative to the combined weight of binder and zeolite. Preferably, theamount of zeolite is at least about 50 wt % of the combined weight ofzeolite and binder, such as at least about 60 wt % or from about 65 wt %to about 80 wt %.

Without being bound by any particular theory, it is believed that use ofa low surface area binder reduces the amount of binder surface areaavailable for the hydrogenation metals supported on the catalyst. Thisleads to an increase in the amount of hydrogenation metals that aresupported within the pores of the molecular sieve in the catalyst.

A zeolite can be combined with binder in any convenient manner. Forexample, a bound catalyst can be produced by starting with powders ofboth the zeolite and binder, combining and mulling the powders withadded water to form a mixture, and then extruding the mixture to producea bound catalyst of a desired size. Extrusion aids can also be used tomodify the extrusion flow properties of the zeolite and binder mixture.The amount of framework alumina in the catalyst may range from 0.1 to3.33 wt %, or 0.1 to 2.7 wt %, or 0.2 to 2 wt %, or 0.3 to 1 wt %.

Effective conditions for catalytic dewaxing of a feedstock in thepresence of a dewaxing catalyst can include a temperature of from 280°C. to 450° C., preferably 343° C. to 435° C. a hydrogen partial pressureof from 3.5 MPag to 34.6 MPag (500 psig to 5000 psig), preferably 4.8MPag to 20.8 MPag, and a hydrogen circulation rate of from 178 m³/m³(1000 SCF/B) to 1781 m³/m³ (10,000 scf/B), preferably 213 m³/m³ (1200SCF/B) to 1068 m³/m³ (6000 SCF/B). The LHSV can be from about 0.2 h⁻¹ toabout 10 h⁻¹, such as from about 0.5 h⁻¹ to about 5 h⁻¹ and/or fromabout 1 h⁻¹ to about 4 h⁻¹.

Before and/or after catalytic dewaxing, the hydroprocessed deasphaltedoil (i.e., at least a lubricant boiling range portion thereof) canoptionally be exposed to an aromatic saturation catalyst, which canalternatively be referred to as a hydrofinishing catalyst. Exposure tothe aromatic saturation catalyst can occur either before or afterfractionation. If aromatic saturation occurs after fractionation, thearomatic saturation can be performed on one or more portions of thefractionated product. Alternatively, the entire effluent from the lasthydrocracking or dewaxing process can be hydrofinished and/or undergoaromatic saturation.

Hydrofinishing and/or aromatic saturation catalysts can includecatalysts containing Group VI metals, Group VIII metals, and mixturesthereof. In an embodiment, preferred metals include at least one metalsulfide having a strong hydrogenation function. In another embodiment,the hydrofinishing catalyst can include a Group VIII noble metal, suchas Pt, Pd, or a combination thereof. The mixture of metals may also bepresent as bulk metal catalysts wherein the amount of metal is about 30wt. % or greater based on catalyst. For supported hydrotreatingcatalysts, suitable metal oxide supports include low acidic oxides suchas silica, alumina, silica-aluminas or titania, preferably alumina. Thepreferred hydrofinishing catalysts for aromatic saturation will compriseat least one metal having relatively strong hydrogenation function on aporous support. Typical support materials include amorphous orcrystalline oxide materials such as alumina, silica, and silica-alumina.The support materials may also be modified, such as by halogenation, orin particular fluorination. The metal content of the catalyst is oftenas high as about 20 weight percent for non-noble metals. In anembodiment, a preferred hydrofinishing catalyst can include acrystalline material belonging to the M41S class or family of catalysts.The M41 S family of catalysts are mesoporous materials having highsilica content. Examples include MCM-41, MCM-48 and MCM-50. A preferredmember of this class is MCM-41.

Hydrofinishing conditions can include temperatures from about 125° C. toabout 425° C., preferably about 180° C. to about 280° C., a hydrogenpartial pressure from about 500 psig (3.4 MPa) to about 3000 psig (20.7MPa), preferably about 1500 psig (10.3 MPa) to about 2500 psig (17.2MPa), and liquid hourly space velocity from about 0.1 hr⁻¹ to about 5hr⁻¹ LHSV, preferably about 0.5 hr⁻¹ to about 1.5 hr⁻¹. Additionally, ahydrogen treat gas rate of from 35.6 m³/m³ to 1781 m³/m³ (200 SCF/B to10,000 SCF/B) can be used.

Solvent Processing of Catalytically Dewaxed Effluent or Input Flow toCatalytic Dewaxing

For deasphalted oils derived from propane deasphalting, the furtherhydroprocessing (including catalytic dewaxing) can be sufficient to formlubricant base stocks with low haze formation and unexpectedcompositional properties. For deasphalted oils derived from C₄₊deasphalting, after the further hydroprocessing (including catalyticdewaxing), the resulting catalytically dewaxed effluent can be solventprocessed to form one or more lubricant base stock products with areduced or eliminated tendency to form haze. The type of solventprocessing can be dependent on the nature of the initial hydroprocessing(hydrotreatment and/or hydrocracking) and the nature of the furtherhydroprocessing (including dewaxing).

In aspects where the initial hydroprocessing is less severe,corresponding to 10 wt % to 40 wt % conversion relative to −700° F.(370° C.), the subsequent solvent processing can correspond to solventdewaxing. The solvent dewaxing can be performed in a manner similar tothe solvent dewaxing described above. However, this solvent dewaxing canbe used to produce a Group II lubricant base stock. In some aspects,when the initial hydroprocessing corresponds to wt % to 40 wt %conversion relative to 370° C., the catalytic dewaxing during furtherhydroprocessing can also be performed at lower severity, so that atleast 6 wt % wax remains in the catalytically dewaxed effluent, or atleast 8 wt %, or at least 10 wt %, or at least 12 wt %, or at least 15wt %, such as up to 20 wt %. The solvent dewaxing can then be used toreduce the wax content in the catalytically dewaxed effluent by 2 wt %to 10 wt %. This can produce a solvent dewaxed oil product having a waxcontent of 0.1 wt % to 12 wt %, or 0.1 wt % to 10 wt %, or 0.1 wt % to 8wt %, or 0.1 wt % to 6 wt %, or 1 wt % to 12 wt %, or 1 wt % to 10 wt %,or 1 wt % to 8 wt %, or 4 wt % to 12 wt %, or 4 wt % to 10 wt %, or 4 wt% to 8 wt %, or 6 wt % to 12 wt %, or 6% wt % to 10 wt %. In particular,the solvent dewaxed oil can have a wax content of 0.1 wt % to 12 wt %,or 0.1 wt % to 6 wt %, or 1 wt % to 10 wt %, or 4 wt % to 12 wt %.

In other aspects, the subsequent solvent processing can correspond tosolvent extraction. Solvent extraction can be used to reduce thearomatics content and/or the amount of polar molecules. The solventextraction process selectively dissolves aromatic components to form anaromatics-rich extract phase while leaving the more paraffiniccomponents in an aromatics-poor raffinate phase. Naphthenes aredistributed between the extract and raffinate phases. Typical solventsfor solvent extraction include phenol, furfural and N-methylpyrrolidone. By controlling the solvent to oil ratio, extractiontemperature and method of contacting distillate to be extracted withsolvent, one can control the degree of separation between the extractand raffinate phases. Any convenient type of liquid-liquid extractor canbe used, such as a counter-current liquid-liquid extractor. Depending onthe initial concentration of aromatics in the deasphalted oil, theraffinate phase can have an aromatics content of 5 wt % to 25 wt %. Fortypical feeds, the aromatics contents can be at least 10 wt %.

Optionally, the raffinate from the solvent extraction can beunder-extracted. In such aspects, the extraction is carried out underconditions such that the raffinate yield is maximized while stillremoving most of the lowest quality molecules from the feed. Raffinateyield may be maximized by controlling extraction conditions, forexample, by lowering the solvent to oil treat ratio and/or decreasingthe extraction temperature. In various aspects, the raffinate yield fromsolvent extraction can be at least 40 wt %, or at least 50 wt %, or atleast 60 wt %, or at least 70 wt %.

The solvent processed oil (solvent dewaxed or solvent extracted) canhave a pour point of −6° C. or less, or −10° C. or less, or −15° C. orless, or −20° C. or less, depending on the nature of the targetlubricant base stock product. Additionally or alternately, the solventprocessed oil (solvent dewaxed or solvent extracted) can have a cloudpoint of −2° C. or less, or −5° C. or less, or −10° C. or less,depending on the nature of the target lubricant base stock product. Pourpoints and cloud points can be determined according to ASTM D97 and ASTMD2500, respectively. The resulting solvent processed oil can be suitablefor use in forming one or more types of Group II base stocks. Theresulting solvent dewaxed oil can have a viscosity index of at least 80,or at least 90, or at least 95, or at least 100, or at least 110, or atleast 120. Viscosity index can be determined according to ASTM D2270.Preferably, at least 10 wt % of the resulting solvent processed oil (orat least 20 wt %, or at least 30 wt %) can correspond to a Group IIbright stock having a kinematic viscosity at 100° C. of at least 14 cSt,or at least 15 cSt, or at least 20 cSt, or at least 25 cSt, or at least30 cSt, or at least 32 cSt, such as up to 50 cSt or more. Additionallyor alternately, the Group II bright stock can have a kinematic viscosityat 40° C. of at least 300 cSt, or at least 320 cSt, or at least 340 cSt,or at least 350 cSt, such as up to 500 cSt or more. Kinematic viscositycan be determined according to ASTM D445. Additionally or alternately,the Conradson Carbon residue content can be about 0.1 wt % or less, orabout 0.02 wt % or less. Conradson Carbon residue content can bedetermined according to ASTM D4530. Additionally or alternately, theresulting base stock can have a turbidity of at least 1.5 (incombination with a cloud point of less than 0° C.), or can have aturbidity of at least 2.0, and/or can have a turbidity of 4.0 or less,or 3.5 or less, or 3.0 or less. In particular, the turbidity can be 1.5to 4.0, or 1.5 to 3.0, or 2.0 to 4.0, or 2.0 to 3.5.

The reduced or eliminated tendency to form haze for the lubricant basestocks formed from the solvent processed oil can be demonstrated by thereduced or minimized difference between the cloud point temperature andpour point temperature for the lubricant base stocks. In variousaspects, the difference between the cloud point and pour point for theresulting solvent dewaxed oil and/or for one or more Group II lubricantbase stocks, including one or more bright stocks, formed from thesolvent processed oil, can be 22° C. or less, or 20° C. or less, or 15°C. or less, or 10° C. or less, such as down to about 1° C. ofdifference.

In some alternative aspects, the above solvent processing can beperformed prior to catalytic dewaxing.

Group II Base Stock Products

For deasphalted oils derived from propane, butane, pentane, hexane andhigher or mixtures thereof, the further hydroprocessing (includingcatalytic dewaxing) and potentially solvent processing can be sufficientto form lubricant base stocks with low haze formation (or no hazeformation) and novel compositional properties. Traditional productsmanufactured today with kinematic viscosity of about 32 cSt at 100° C.contain aromatics that are >10% and/or sulfur that is >0.03% of the baseoil.

In various aspects, base stocks produced according to methods describedherein can have a kinematic viscosity of at least 14 cSt, or at least 20cSt, or at least 25 cSt, or at least 30 cSt, or at least 32 cSt at 100°C. and can contain less than 10 wt % aromatics/greater than 90 wt %saturates and less than 0.03% sulfur. Optionally, the saturates contentcan be still higher, such as greater than 95 wt %, or greater than 97 wt%. In addition, detailed characterization of the branchiness (branching)of the molecules by C-NMR reveals a high degree of branch points asdescribed further below in the examples. This can be quantified byexamining the absolute number of methyl branches, or ethyl branches, orpropyl branches individually or as combinations thereof. This can alsobe quantified by looking at the ratio of branch points (methyl, ethyl,or propyl) compared to the number of internal carbons, labeled asepsilon carbons by C-NMR. This quantification of branching can be usedto determine whether a base stock will be stable against haze formationover time. For ¹³C-NMR results reported herein, samples were prepared tobe 25-30 wt % in CDCl₃ with 7% Chromium (III)-acetylacetonate added as arelaxation agent. ¹³C NMR experiments were performed on a JEOL ECS NMRspectrometer for which the proton resonance frequency is 400 MHz.Quantitative ¹³C NMR experiments were performed at 27° C. using aninverse gated decoupling experiment with a 45° flip angle, 6.6 secondsbetween pulses, 64 K data points and 2400 scans. All spectra werereferenced to TMS at 0 ppm. Spectra were processed with 0.2-1 Hz of linebroadening and baseline correction was applied prior to manualintegration. The entire spectrum was integrated to determine the mole %of the different integrated areas as follows: 170-190 PPM (aromatic C);30-29.5 PPM (epsilon carbons): 15-14.5 PPM (terminal and pendant propylgroups) 14.5-14 PPM—Methyl at the end of a long chain (alpha); 12-10 PPM(pendant and terminal ethyl groups). Total methyl content was obtainedfrom proton NMR. The methyl signal at 0-1.1 PPM was integrated. Theentire spectrum was integrated to determine the mole % of methyls.Average carbon numbers obtained from gas chromatography were used toconvert mole % methyls to total methyls.

Also unexpected in the composition is the discovery using FourierTransform Ion Cyclotron Resonance-Mass Spectrometry (FTICR-MS) and/orField Desorption Mass Spectrometry (FDMS) that the prevalence of smallernaphthenic ring structures below 6 or below 7 or below 8 naphthene ringscan be similar but the residual numbers of larger naphthenic ringsstructures with 7 or more rings or 8+ rings or 9+ rings or 10+ rings isdiminished in base stocks that are stable against haze formation.

For FTICR-MS results reported herein, the results were generatedaccording to the method described in U.S. Pat. No. 9,418,828. The methoddescribed in U.S. Pat. No. 9,418,828 generally involves using laserdesorption with Ag ion complexation (LDI-Ag) to ionize petroleumsaturates molecules (including 538° C.+ molecules) without fragmentationof the molecular ion structure. Ultra-high resolution Fourier TransformIon Cyclotron Resonance Mass Spectrometry is applied to determine exactelemental formula of the saturates-Ag cations and correspondingabundances. The saturates fraction composition can be arranged byhomologous series and molecular weights. The portion of U.S. Pat. No.9,418,828 related to determining the content of saturate ring structuresin a sample is incorporated herein by reference.

For FDMS results reported herein. Field desorption (FD) is a softionization method in which a high-potential electric field is applied toan emitter (a filament from which tiny “whiskers” have formed) that hasbeen coated with a diluted sample resulting in the ionization of gaseousmolecules of the analyte. Mass spectra produced by FD are dominated bymolecular radical cations M⁺ or in some cases protonated molecular ions[M+H]⁺. Because FDMS cannot distinguish between molecules with ‘n’naphthene rings and molecules with ‘n+7’ rings, the FDMS data was“corrected” by using the FTICR-MS data from the most similar sample. TheFDMS correction was performed by applying the resolved ratio of “n” to“n+7” rings from the FTICR-MS to the unresolved FDMS data for thatparticular class of molecules. Hence, the FDMS data is shown as“corrected” in the figures.

Base oils of the compositions described above have further been found toprovide the advantage of being haze free upon initial production andremaining haze free for extended periods of time. This is an advantageover the prior art of high saturates heavy base stocks that wasunexpected.

Additionally, it has been found that these base stocks can be blendedwith additives to form formulated lubricants, such as but not limited tomarine oils, engine oils, greases, paper machine oils, and gear oils.These additives may include, but are not restricted to, detergents,dispersants, antioxidants, viscosity modifiers, and pour pointdepressants. More generally, a formulated lubricating including a basestock produced from a deasphalted oil may additionally contain one ormore of the other commonly used lubricating oil performance additivesincluding but not limited to antiwear agents, dispersants, otherdetergents, corrosion inhibitors, rust inhibitors, metal deactivators,extreme pressure additives, anti-seizure agents, wax modifiers,viscosity index improvers, viscosity modifiers, fluid-loss additives,seal compatibility agents, friction modifiers, lubricity agents,anti-staining agents, chromophoric agents, defoamants, demulsifiers,emulsifiers, densifiers, wetting agents, gelling agents, tackinessagents, colorants, and others. For a review of many commonly usedadditives, see Klamann in Lubricants and Related Products. VerlagChemie, Deerfield Beach, Fla.; ISBN 0-89573-177-0. These additives arecommonly delivered with varying amounts of diluent oil, that may rangefrom 5 weight percent to 50 weight percent.

When so blended, the performance as measured by standard low temperaturetests such as the Mini-Rotary Viscometer (MRV) and Brookfield test hasbeen shown to be superior to formulations blended with traditional baseoils.

It has also been found that the oxidation performance, when blended intoindustrial oils using common additives such as, but not restricted to,defoamants, pour point depressants, antioxidants, rust inhibitors, hasexemplified superior oxidation performance in standard oxidation testssuch as the US Steel Oxidation test compared to traditional base stocks.

Other performance parameters such as interfacial properties, depositcontrol, storage stability, and toxicity have also been examined and aresimilar to or better than traditional base oils.

In addition to being blended with additives, the base stocks describedherein can also be blended with other base stocks to make a base oil.These other base stocks include solvent processed base stocks,hydroprocessed base stocks, synthetic base stocks, base stocks derivedfrom Fisher-Tropsch processes, PAO, and naphthenic base stocks.Additionally or alternately, the other base stocks can include Group Ibase stocks, Group II base stocks, Group III base stocks, Group IV basestocks, and/or Group V base stocks. Additionally or alternately, stillother types of base stocks for blending can include hydrocarbylaromatics, alkylated aromatics, esters (including synthetic and/orrenewable esters), and or other non-conventional or unconventional basestocks. These base oil blends of the inventive base stock and other basestocks can also be combined with additives, such as those mentionedabove, to make formulated lubricants.

Configuration Examples

FIG. 1 schematically shows a first configuration for processing of adeasphalted oil feed 110. Optionally, deasphalted oil feed 110 caninclude a vacuum gas oil boiling range portion. In FIG. 1, a deasphaltedoil feed 110 is exposed to hydrotreating and/or hydrocracking catalystin a first hydroprocessing stage 120. The hydroprocessed effluent fromfirst hydroprocessing stage 120 can be separated into one or more fuelsfractions 127 and a 370° C.+ fraction 125. The 370° C.+ fraction 125 canbe solvent dewaxed 130 to form one or more lubricant base stockproducts, such as one or more light neutral or heavy neutral base stockproducts 132 and a bright stock product 134.

FIG. 2 schematically shows a second configuration for processing adeasphalted oil feed 110. In FIG. 2, solvent dewaxing stage 130 isoptional. The effluent from first hydroprocessing stage 120 can beseparated to form at least one or more fuels fractions 127, a first 370°C.+ portion 245, and a second optional 370° C.+ portion 225 that can beused as the input for optional solvent dewaxing stage 130. The first370° C.+ portion 245 can be used as an input for a secondhydroprocessing stage 250. The second hydroprocessing stage cancorrespond to a sweet hydroprocessing stage for performing catalyticdewaxing, aromatic saturation, and optionally further performinghydrocracking. In FIG. 2, at least a portion 253 of the catalyticallydewaxed output 255 from second hydroprocessing stage 250 can be solventdewaxed 260 to form at least a solvent processed lubricant boiling rangeproduct 265 that has a T10 boiling point of at least 510° C. and thatcorresponds to a Group II bright stock.

FIG. 3 schematically shows another configuration for producing a GroupII bright stock. In FIG. 3, at least a portion 353 of the catalyticallydewaxed output 355 from the second hydroprocessing stage 250 is solventextracted 370 to form at least a processed lubricant boiling rangeproduct 375 that has a T10 boiling point of at least 510° C. and thatcorresponds to a Group II bright stock.

FIG. 6 schematically shows yet another configuration for producing aGroup II bright stock. In FIG. 6, a vacuum resid feed 675 and adeasphalting solvent 676 is passed into a deasphalting unit 680. In someaspects, deasphalting unit 680 can perform propane deasphalting, but inother aspects a C₄₊ solvent can be used. Deasphalting unit 680 canproduce a rock or asphalt fraction 682 and a deasphalted oil 610.Optionally, deasphalted oil 610 can be combined with another vacuum gasoil boiling range feed 671 prior to being introduced into first (sour)hydroprocessing stage 620. A lower boiling portion 627 of the effluentfrom hydroprocessing stage 620 can be separated out for further useand/or processing as one or more naphtha fractions and/or distillatefractions. A higher boiling portion 625 of the hydroprocessing effluentcan be a) passed into a second (sweet) hydroprocessing stage 650 and/orb) withdrawn 626 from the processing system for use as a fuel, such as afuel oil or fuel oil blendstock. Second hydroprocessing stage 650 canproduce an effluent that can be separated to form one or more fuelsfractions 657 and one or more lubricant base stock fractions 655, suchas one or more bright stock fractions.

Example 1

In this example, a deasphalted oil was processed in a configurationsimilar to FIG. 1. The deasphalted oil was derived from deasphalting ofa resid fraction using pentane as a solvent. The properties of thedeasphalted oil are shown in Table 1. The yield of deasphalted oil was75 wt % relative to the feed.

TABLE 1 Deasphalted Oil from Pentane Deasphalting (75 wt % yield) APIGravity 12.2 Sulfur (wt %) 3.72 Nitrogen (wppm) 2557 Ni (wppm) 7.1 V(wppm) 19.7 CCR (wt %) 12.3 Wax (wt %) 4.6 GCD Distillation (wt %) (°C.)  5% 522 10% 543 30% 586 50% 619 70% 660 90% 719

The deasphalted oil in Table 1 was processed at 0.2 hr⁻¹ LHSV, a treatgas rate of 8000 scf/b, and a pressure of 2250 psig over a catalyst fillof 50 vol % demetalization catalyst, 42.5 vol % hydrotreating catalyst,and 7.5% hydrocracking catalyst by volume. The demetallization catalystwas a commercially available large pore supported demetallizationcatalyst. The hydrotreating catalyst was a stacked bed of commerciallyavailable supported NiMo hydrotreating catalyst and commerciallyavailable bulk NiMo catalyst. The hydrocracking catalyst was a standarddistillate selective catalyst used in industry. Such catalysts typicallyinclude NiMo or NiW on a zeolite/alumina support. Such catalyststypically have less than 40 wt % zeolite of a zeolite with a unit cellsize of less than 34.38 Angstroms. A preferred zeolite content can beless than 25 wt % and/or a preferred unit cell size can be less than24.32 Angstroms. Activity for such catalysts can be related to the unitcell size of the zeolite, so the activity of the catalyst can beadjusted by selecting the amount of zeolite. The feed was exposed to thedemetallization catalyst at 745° F. (396° C.) and exposed to thecombination of the hydrotreating and hydrocracking catalyst at 765° F.(407° C.) in an isothermal fashion.

The hydroprocessed effluent was distilled to form a 510° C.+ fractionand a 510° C.− fraction. The 510° C.− fraction could be solvent dewaxedto produce lower viscosity (light neutral and/or heavy neutral)lubricant base stocks. The 510° C.+ fraction was solvent dewaxed toremove the wax. The properties of the resulting Group I bright stock areshown in Table 2. The low cloud point demonstrates the haze freepotential of the bright stock, as the cloud point differs from the pourpoint by less than 5° C.

TABLE 2 Group I bright stock properties Product Fraction 510° C.+ VI98.9 KV @100° C. 27.6 KV @40° C. 378 Pour Pt (° C.) −15 Cloud Pt (° C.)−11

Example 2

In this example, a deasphalted oil was processed in a configurationsimilar to FIG. 1. The deasphalted oil described in Table 1 of Example 1was mixed with a lighter boiling range vacuum gas oil in a ratio of 65wt % deasphalted oil to 35 wt % vacuum gas oil. The properties of themixed feed are shown in Table 3.

TABLE 3 Pentane deasphalted oil (65%) and vacuum gas oil (35%)properties API Gravity 13.7 Sulfur (wt %) 3.6 Nitrogen (wppm) 2099 Ni(wppm) 5.2 V (wppm) 14.0 CCR (wt %) 8.1 Wax (wt %) 4.2 GCD Distillation(wt %) (° C.)  5% 422 10% 465 30% 541 50% 584 70% n/a 90% 652

The mixed feed was treated with conditions and catalysts similar tothose used in Example 1, with the exception of an increase in reactortemperature to adjust for catalyst aging and slightly higher conversionamounts. The feed was exposed to the demetallization catalyst at 750° F.(399° C.) and the hydrotreating/hydrocracking catalysts at 770° F. (410°C.). After separation to remove fuels fractions, the 370° C.+ portionwas solvent dewaxed. Bright stocks were formed from the solvent dewaxedeffluent using a 510° C.+ cut and using a second deep cut at 571° C.+.The properties of the two types of possible bright stocks are shown inTable 4. (For clarity, the 510° C.+ bright stock includes the 571° C.+portion. A separate sample was used to form the 571° C.+ bright stockshown in Table 4.)

TABLE 4 Group I bright stocks Product Fraction 510° C.+ 571° C.+ VI108.9 112.2 KV @100° C. 19.9 35.4 KV @40° C. 203 476 Pour Pt (° C.) −14Cloud Pt (° C.) −12

Example 3

A configuration similar to FIG. 1 was used to process a deasphalted oilformed from butane deasphalting (55 wt % deasphalted oil yield). Theproperties of the deasphalted oil are shown in Table 5.

TABLE 5 Butane deasphalted oil (55 wt % yield) API Gravity 14.0 Sulfur(wt %) 2.8 Nitrogen (wppm) 2653 Ni (wppm) 9.5 V (wppm) 14.0 CCR (wt %)8.3 Wax (wt %) 3.9 GCD Distillation (wt %) (° C.)  5% 480 10% 505 30%558 50% 597 70% 641 90% 712

The deasphalted oil was converted to bright stock with low hazecharacteristics using process conditions and catalysts similar to thosein Example 1, with the exception of the reaction temperatures. Thedeasphalted oil was exposed to the first hydroprocessing stage in twoseparate runs with all catalysts (demetallization, hydrotreating,hydrocracking) at a temperature of 371° C. The lower conversion in thesecond run is believed to be due to deactivation of catalyst, as wouldtypically be expected for this type of heavy feed. The effluents fromboth runs were distilled to form a 510° C.+ fraction. The 510° C.+fraction was solvent dewaxed. The resulting solvent dewaxed oils had theproperties shown in Table 6. Table 6 also shows the difference in 370°C. conversion during the two separate runs.

TABLE 6 Group I bright stock properties Product Fraction First runSecond run VI 97.5 90 KV @100° C. 27.3 35.2 KV @40° C. 378 619 Pour Pt(° C.) −19 −18.5 Cloud Pt (° C.) −13 −15 Conversion (wt % 54.3 41.3relative to 510° C.)

The low cloud point of both samples demonstrates the haze free potentialof the bright stock, as the cloud point differs from the pour point forboth samples by 6° C. or less.

Example 4

A configuration similar to FIG. 2 was used to process a deasphalted oilformed from butane deasphalting (55 wt % deasphalted oil yield). Theproperties of the deasphalted oil are shown in Table 5. The deasphaltedoil was then hydroprocessed according to the conditions in Example 3. Atleast a portion of the hydroprocessed deasphalted oil was then exposedto further hydroprocessing without being solvent dewaxed.

The non-dewaxed hydrotreated product was processed over combinations oflow unit cell size USY and ZSM-48. The resulting product had a high pourcloud spread differential resulting in a hazy product. However, apost-treat solvent dewaxing was able to remove that haze at a modest 3%loss in yield. Processing conditions for the second hydroprocessingstage included a hydrogen pressure of 1950 psig and a treat gas rate of4000 scf/b. The feed into the second hydroprocessing stage was exposedto a) a 0.6 wt % Pt on USY hydrocracking catalyst (unit cell size lessthan 24.32, silica to alumina ratio of 35, 65 wt % zeolite/35 wt %binder) at 3.1 hr⁻¹ LHSV and a temperature of 665° F.; b) a 0.6 wt % Pton ZSM-48 dewaxing catalyst (90:1 silica to alumina, 65 wt % zeolite/35wt % binder) at 2.1 hr⁻¹ LHSV and a temperature of 635° F.; and c) 0.3wt % Pt/0.9 wt % Pd on MCM-41 aromatic saturation catalyst (65 wt %zeolite/35 wt % binder) at 0.9 hr LHSV and a temperature of 480° F. Theresulting properties of the 510° C.+ portion of the catalyticallydewaxed effluent are shown in Table 7, along with the 510° C. conversionwithin the hydrocracking/catalytic dewaxing/aromatic saturationprocesses

TABLE 7 Catalytically dewaxed effluent Product Fraction VI 104.4 KV@100° C. 26.6 KV @40° C. 337 Pour Pt (° C.) −28 Cloud Pt (° C.) 8.4Conversion (wt % 49 relative to 510° C.)

The product shown in Table 7 was hazy. However, an additional step ofsolvent dewaxing with a loss of only 2.5 wt % yield resulted in a brightand clear product with the properties shown in Table 8. It is noted thatthe pour point and the cloud point differ by slightly less than 20° C.The solvent dewaxing conditions included a slurry temperature of −30°C., a solvent corresponding to 35 wt % methyl ethyl ketone and 65 wt %toluene, and a solvent dilution ratio of 3:1.

TABLE 8 Solvent Processed 510° C.+ product (Group II bright stock)Product Fraction VI 104.4 KV @100° C. 25.7 KV @40° C. 321 Pour Pt (° C.)−27 Cloud Pt (° C.) −7.1

Example 5

The deasphalted oil and vacuum gas oil mixture shown in Table 3 ofExample 2 was processed in a configuration similar to FIG. 3. Theconditions and catalysts in the first hydroprocessing stage were similarto Example 1, with the exception of adjustments in temperature toaccount for catalyst aging. The demetallization catalyst was operated at744° F. (396° C.) and the HDT/HDC combination was operated at 761° F.(405° C.). This resulted in conversion relative to 510° C. of 73.9 wt %and conversion relative to 370° C. of 50 wt %. The hydroprocessedeffluent was separated to remove fuels boiling range portions from a370° C.+ portion. The resulting 370° C.+ portion was then furtherhydroprocessed. The further hydroprocessing included exposing the 370°C.+ portion to a 0.6 wt % Pt on ZSM-48 dewaxing catalyst (70:1 silica toalumina ratio, 65 wt % zeolite to 35 wt % binder) followed by a 0.3 wt %Pt/0.9 wt % Pd on MCM-41 aromatic saturation catalyst (65% zeolite to 35wt % binder). The operating conditions included a hydrogen pressure of2400 psig, a treat gas rate of 5000 scf/b, a dewaxing temperature of658° F. (348° C.), a dewaxing catalyst space velocity of 1.0 hr⁻¹, anaromatic saturation temperature of 460° F. (238° C.), and an aromaticsaturation catalyst space velocity of 1.0 hr⁻¹. The properties of the560° C.+ portion of the catalytically dewaxed effluent are shown inTable 9. Properties for a raffinate fraction and an extract fractionderived from the catalytically dewaxed effluent are also shown.

TABLE 9 Catalytically dewaxed effluent Product Fraction 560° C.+Raffinate CDW effluent (yield 92.2%) Extract API 30.0 30.2 27.6 VI 104.2105.2 89 KV @100° C. 29.8 30.3 29.9 KV @40° C. 401 405 412 Pour Pt (°C.) −21 −30 Cloud Pt (° C.) 7.8 −24

Although the catalytically dewaxed effluent product was initially clear,haze developed within 2 days. Solvent dewaxing of the catalyticallydewaxed effluent product in Table 9 did not reduce the cloud pointsignificantly (cloud after solvent dewaxing of 6.5° C.) and removed onlyabout 1 wt % of wax, due in part to the severity of the prior catalyticdewaxing. However, extracting the catalytically dewaxed product shown inTable 9 with n-methyl pyrrolidone (NMP) at a solvent/water ratio of 1and at a temperature of 100° C. resulted in a clear and bright productwith a cloud point of −24° C. that appeared to be stable against hazeformation. The extraction also reduced the aromatics content of thecatalytically dewaxed product from about 2 wt % aromatics to about 1 wt% aromatics. This included reducing the 3-ring aromatics content of thecatalytically dewaxed effluent (initially about 0.2 wt %) by about 80%.This result indicates a potential relationship between waxy hazeformation and the presence of polynuclear aromatics in a bright stock.

Example 6

A feed similar to Example 5 were processed in a configuration similar toFIG. 2, with various processing conditions were modified. The initialhydroprocessing severity was reduced relative to the conditions inExample 5 so that the initial hydroprocessing conversion was 59 wt %relative to 510° C. and 34.5 wt % relative to 370° C. These lowerconversions were achieved by operating the demetallization catalyst at739° F. (393° C.) and the hydrotreating/hydrocracking catalystcombination at 756° F. (402° C.).

The hydroprocessed effluent was separated to separate fuels boilingrange fraction(s) from the 370° C.+ portion of the hydroprocessedeffluent. The 370° C.+ portion was then treated in a secondhydroprocessing stage over the hydrocracking catalyst, and dewaxingcatalyst described in Example 4. Additionally, a small amount of ahydrotreating catalyst (hydrotreating catalyst LHSV of 10 hr⁻¹) wasincluded prior to the hydrocracking catalyst, and the feed was exposedto the hydrotreating catalyst under substantially the same conditions asthe hydrocracking catalyst. The reaction conditions included a hydrogenpressure of 2400 psig and a treat gas rate of 5000 scf/b. In a firstrun, the second hydroprocessing conditions were selected to under dewaxthe hydroprocessed effluent. The under-dewaxing conditions correspondedto a hydrocracking temperature of 675° F. (357° C.), a hydrocrackingcatalyst LHSV of 1.2 hr⁻¹, a dewaxing temperature of 615° F. (324° C.),a dewaxing catalyst LHSV of 1.2 hr⁻¹, an aromatic saturation temperatureof 460° F. (238° C.), and an aromatic saturation catalyst LHSV of 1.2hr⁻¹. In a second run, the second hydroprocessing conditions wereselected to more severely dewax the hydroprocessed effluent. The higherseverity dewaxing conditions corresponded to a hydrocracking temperatureof 675° F. (357° C.), a hydrocracking catalyst LHSV of 1.2 hr⁻¹, adewaxing temperature of 645° F. (340° C.), a dewaxing catalyst LHSV of1.2 hr⁻¹, an aromatic saturation temperature of 460° F. (238° C.), andan aromatic saturation catalyst LHSV of 1.2 hr⁻¹. The 510° C.+ portionsof the catalytically dewaxed effluent are shown in Table 10.

TABLE 10 Catalytically dewaxed effluents Product Fraction Under-dewaxedHigher severity VI 106.6 106.4 KV @100° C. 37.6 30.5 KV @40° C. 551 396Pour Pt (° C.) −24 −24 Cloud Pt (° C.) 8.6 4.9

Both samples in Table 10 were initially bright and clear, but a hazedeveloped in both samples within one week. Both samples were solventdewaxed under the conditions described in Example 4. This reduced thewax content of the under-dewaxed sample to 6.8 wt % and the wax contentof the higher severity dewaxing sample to 1.1 wt %. The higher severitydewaxing sample still showed a slight haze. However, the under-dewaxedsample, after solvent dewaxing, had a cloud point of −21° C. andappeared to be stable against haze formation.

Example 7—Viscosity and Viscosity Index Relationships

FIG. 4 shows an example of the relationship between processing severity,kinematic viscosity, and viscosity index for lubricant base stocksformed from a deasphalted oil. The data in FIG. 4 corresponds tolubricant base stocks formed form a pentane deasphalted oil at 75 wt %yield on resid feed. The deasphalted oil had a solvent dewaxed VI of75.8 and a solvent dewaxed kinematic viscosity at 100° C. of 333.65.

In FIG. 4, kinematic viscosities (right axis) and viscosity indexes(left axis) are shown as a function of hydroprocessing severity (510°C.+ conversion) for a deasphalted oil processed in a configurationsimilar to FIG. 1, with the catalysts described in Example 1. As shownin FIG. 4, increasing the hydroprocessing severity can provide VI upliftso that deasphalted oil can be converted (after solvent dewaxing) tolubricant base stocks. However, increasing severity also reduces thekinematic viscosity of the 510° C.+ portion of the base stock, which canlimit the yield of bright stock. The 370° C.-510° C. portion of thesolvent dewaxed product can be suitable for forming light neutral and/orheavy neutral base stocks, while the 510° C.+ portion can be suitablefor forming bright stocks and/or heavy neutral base stocks.

Example 8—Variations in Sweet and Sour Hydrocracking

In addition to providing a method for forming Group II base stocks froma challenged feed, the methods described herein can also be used tocontrol the distribution of base stocks formed from a feed by varyingthe amount of conversion performed in sour conditions versus sweetconditions. This is illustrated by the results shown in FIG. 5.

In FIG. 5, the upper two curves show the relationship between the cutpoint used for forming a lubricant base stock of a desired viscosity(bottom axis) and the viscosity index of the resulting base stock (leftaxis). The curve corresponding to the circle data points representsprocessing of a C₅ deasphalted oil using a configuration similar to FIG.2, with all of the hydrocracking occurring in the sour stage. The curvecorresponding to the square data points corresponds to performingroughly half of the hydrocracking conversion in the sour stage and theremaining hydrocracking conversion in the sweet stage (along with thecatalytic dewaxing). The individual data points in each of the uppercurves represent the yield of each of the different base stocks relativeto the amount of feed introduced into the sour processing stage. It isnoted that summing the data points within each curve shows the sametotal yield of base stock, which reflects the fact that the same totalamount of hydrocracking conversion was performed in both types ofprocessing runs. Only the location of the hydrocracking conversion (allsour, or split between sour and sweet) was varied.

The lower pair of curves provides additional information about the samepair of process runs. As for the upper pair of curves, the circle datapoints in the lower pair of curves represent all hydrocracking in thesour stage and the square data points correspond to a split ofhydrocracking between sour and sweet stages. The lower pair of curvesshows the relationship between cut point (bottom axis) and the resultingkinematic viscosity at 100° C. (right axis). As shown by the lower pairof curves, the three cut point represent formation of a light neutralbase stock (5 or 6 cSt), a heavy neutral base stock (10-12 cSt), and abright stock (about 30 cSt). The individual data points for the lowercurves also indicate the pour point of the resulting base stock.

As shown in FIG. 5, altering the conditions under which hydrocracking isperformed can alter the nature of the resulting lubricant base stocks.Performing all of the hydrocracking conversion during the first (sour)hydroprocessing stage can result in higher viscosity index values forthe heavy neutral base stock and bright stock products, while alsoproducing an increased yield of heavy neutral base stock. Performing aportion of the hydrocracking under sweet conditions increased the yieldof light neutral base stock and bright stock with a reduction in heavyneutral base stock yield. Performing a portion of the hydrocrackingunder sweet conditions also reduced the viscosity index values for theheavy neutral base stock and bright stock products. This demonstratesthat the yield of base stocks and/or the resulting quality of basestocks can be altered by varying the amount of conversion performedunder sour conditions versus sweet conditions.

Example 9—Feedstocks and DAOs

Table 1 shows properties of two types of vacuum resid feeds that arepotentially suitable for deasphalting, referred to in this example asResid A and Resid B. Both feeds have an API gravity of less than 6, aspecific gravity of at least 1.0, elevated contents of sulfur, nitrogen,and metals, and elevated contents of carbon residue and n-heptaneinsolubles.

TABLE 11 Resid Feed Properties Resid (566° C.+) Resid A Resid B APIGravity (degrees) 5.4 4.4 Specific Gravity (15° C.) (g/cc) 1.0336 1.0412Total Sulfur (wt %) 4.56 5.03 Nickel (wppm) 43.7 48.7 Vanadium (wppm)114 119 TAN (mg KOH/g) 0.314 0.174 Total Nitrogen (wppm) 4760 4370 BasicNitrogen (wppm) 1210 1370 Carbon Residue (wt %) 24.4 25.8 n-heptaneinsolubles (wt %) 7.68 8.83 Wax (Total − DSC) (wt %) 1.4 1.32 KV @ 100°C. (cSt) 5920 11200 KV @ 135° C. (cSt) 619 988

The resids shown in Table 1 were used to form deasphalted oil. Resid Awas exposed to propane deasphalting (deasphalted oil yield<40%) andpentane deasphalting conditions (deasphalted oil yield˜65%). Resid B wasexposed to butane deasphalting conditions (deasphalted oil yield˜75%).Table 12 shows properties of the resulting deasphalted oils.

TABLE 12 Examples of Deasphalted Oils C₃ DAO C₄ DAO C₅ DAO API Gravity(degrees) 22.4 12.9 12.6 Specific Gravity (15° C.) (g/cc) 0.9138 0.97820.9808 Total Sulfur (wt %) 2.01 3.82 3.56 Nickel (wppm) <0.1 5.2 5.3Vanadium (wppm) <0.1 15.6 17.4 Total Nitrogen (wppm) 504 2116 1933 BasicNitrogen (wppm) 203 <N/A> 478 Carbon Residue (wt %) 1.6 8.3 11.0 KV @100° C. (cSt) 33.3 124 172 VI 96 61 <N/A> SimDist (ASTM D2887) ° C.  5wt % 509 490 527 10 wt % 528 515 546 30 wt % 566 568 588 50 wt % 593 608619 70 wt % 623 657 664 90 wt % 675 <N/A> <N/A> 95 wt % 701 <N/A> <N/A>

As shown in Table 12, the higher severity deasphalting provided bypropane deasphalting results in a different quality of deasphalted oilthan the lower severity C₄ and C₅ deasphalting that was used in thisexample. It is noted that the C₃ DAO has a kinematic viscosity @100° C.of less than 35, while the C₄ DAO and C₅ DAO have kinematic viscositiesgreater than 100. The C₃ DAO also generally has properties more similarto a lubricant base stock product, such as a higher API gravity, a lowermetals content/sulfur content/nitrogen content, lower CCR levels, and/ora higher viscosity index.

ADDITIONAL EMBODIMENTS Embodiment 1

A method for hydroprocessing deasphalted oil, comprising: performingsolvent deasphalting under effective solvent deasphalting conditions ona feedstock having a T5 boiling point of at least about 400° C. (or atleast about 450° C., or at least about 500° C.) to form a first fractioncomprising deasphalted oil and a solvent and a second fractioncomprising deasphalter rock and the solvent, the effective solventdeasphalting conditions producing a yield of deasphalted oil of at leastabout 50 wt % of the feedstock; recovering solvent from at least one ofthe first fraction and the second fraction, the recovering comprisinggenerating heat for the recovering by combustion of a solvent recoveryfuel comprising H₂; gasifying at least a portion of the deasphalter rockto form synthesis gas, the solvent recovery fuel comprising at least aportion of the synthesis gas; desulfurizing at least a portion of thesynthesis gas: separating at least a portion of the desulfurizedsynthesis gas to form an H₂-enriched stream; and hydroprocessing atleast a portion of the deasphalted oil under first effectivehydroprocessing conditions in the presence of an H₂-containing gas toform a hydroprocessed effluent comprising a sulfur content of 500 wppmor less, the H₂-containing gas comprising at least a portion of theH₂-enriched stream.

Embodiment 2

The method of Embodiment 1, further comprising combusting at least aportion of the synthesis gas, the H₂-enriched stream, or a combinationthereof in a combustion zone of a gas turbine for generation ofelectricity.

Embodiment 3

The method of any of the above embodiments, wherein the solventdeasphalting comprises deasphalting with a C₄ solvent, a C₅ solvent, ora combination thereof.

Embodiment 4

The method of any of the above embodiments, further comprisingperforming water gas shift on at least one of the synthesis gas and thedesulfurized synthesis gas prior to separating the at least a portion ofthe desulfurized synthesis gas to form the H₂-enriched stream.

Embodiment 5

The method of any of the above embodiments, a) further comprisingheating the at least a portion of the deasphalted oil prior to thehydroprocessing, the heating comprising combusting at least a portion ofthe synthesis gas, the desulfurized synthesis gas, or a combinationthereof to generate heat; or b) further comprising combusting a portionof the synthesis gas, the desulfurized synthesis gas, or a combinationthereof in a combustion zone of a gas turbine; or c) a combination of a)and b).

Embodiment 6

The method of any of the above embodiments, wherein separating at leasta portion of the desulfurized synthesis gas to form an H₂-enrichedstream comprises performing a swing adsorption process on the at least aportion of the desulfurized synthesis gas to form at least theH₂-enriched purge stream and an H₂-containing purge stream.

Embodiment 7

The method of any of the above embodiments, wherein hydroprocessing atleast a portion of the deasphalted oil comprises demetallizing the atleast a portion of the deasphalted oil, hydrotreating the at least aportion of the deasphalted oil, hydrocracking the at least a portion ofthe deasphalted oil, or a combination thereof.

Embodiment 8

The method of any of the above embodiments, wherein the yield ofdeasphalted oil is at least 55 wt %, or at least 60 wt %, or at least 65wt %, or at least 70 wt %, or at least 75 wt %, or wherein thedeasphalted oil has an aromatics content of at least 50 wt %, or atleast 55 wt %, or at least 60 wt %, or at least 65 wt %, or at least 70wt % based on a weight of the deasphalted oil, or a combination thereof.

Embodiment 9

The method of any of the above embodiments, wherein gasifying at least aportion of the deasphalter rock comprises gasifying deasphalter rocktreated with an anti-tack agent.

10

The method of any of the above embodiments, the method furthercomprising: separating the hydroprocessed effluent to form at least afuels boiling range fraction and a bottoms fraction; and hydroprocessingat least a portion of the hydroprocessed bottoms fraction under secondeffective hydroprocessing conditions, the second effectivehydroprocessing conditions comprising hydrocracking conditions andcatalytic dewaxing conditions, to form a catalytically dewaxed effluentcomprising a 950° F.+ (510° C.+) portion having a VI of at least 80 anda pour point of −6° C. or less.

Embodiment 11

The method of Embodiment 10, wherein the hydroprocessing at least aportion of the hydroprocessed bottoms fraction comprises in the presenceof a second H₂-containing gas, the second H₂-containing gas comprisingat least a second portion of the H₂-enriched stream.

Embodiment 12

The method of Embodiment 10 or 11, wherein the method further comprisesat least one of a) solvent extracting at least a portion of thecatalytically dewaxed effluent to form a solvent processed effluent, b)solvent dewaxing at least a portion of the catalytically dewaxedeffluent to form a solvent processed effluent, wherein the catalyticallydewaxed effluent is underdewaxed, wherein the solvent processed effluentcomprising a cloud point of −2° C. or less.

Embodiment 13

The method of any of the above embodiments, wherein the at least one ofthe hydroprocessed effluent and the at least a portion of thehydroprocessed bottoms fraction comprises less than 200 wppm sulfur,less than 100 wppm nitrogen, or a combination thereof.

Embodiment 14

The method of any of Embodiments 10 to 13, wherein the 950° F.+(510°C.+) portion has a difference between a cloud point temperature and apour point temperature of 25° C. or less, or 15° C. or less, or 10° C.or less, or 6° C. or less.

Embodiment 15

A system for processing deasphalted oil, comprising: a solventdeasphalter comprising a deasphalting tower, a deasphalter feed inlet, adeasphalted oil outlet, a deasphalter rock outlet, one or more solventrecovery stages, and at least one deasphalting heater, the at least onedeasphalting heater providing heat for the deasphalting tower and theone or more solvent recovery stages: a gasifier comprising a gasifierinlet, a steam outlet, and a synthesis gas outlet, the gasifier being influid communication with the deasphalter rock outlet via a gasifierinlet, a water gas shift reactor comprising a shift reactor inlet and ashift reactor outlet, the shift inlet being in fluid communication withthe synthesis gas outlet; a swing reactor comprising a swing reactorinlet and a swing reactor outlet, the swing reactor inlet being in fluidcommunication with the shift reactor outlet; a hydroprocessing reactorcomprising a reactor feed inlet, a reactor hydrogen inlet, and a reactoroutlet, the reactor hydrogen inlet being in fluid communication with theshift reactor outlet, the reactor feed inlet being in fluidcommunication with the deasphalted oil outlet; and a gas turbinecomprising a combustion zone, the combustion zone being in fluidcommunication with at least one of the shift reactor outlet and thesynthesis gas outlet, wherein the at least one deasphalting heater is influid communication with at least one of the synthesis gas outlet andthe shift reactor outlet.

Embodiment 16

The system of Embodiment 15, further comprising a desulfurization stagecomprising a desulfurization inlet and a desulfurization outlet, thedesulfurization inlet being in fluid communication with the synthesisgas outlet, the shift reactor inlet being in indirect fluidcommunication with the synthesis gas outlet via the desulfurizationoutlet of the desulfurization stage, the combustion zone optionallybeing in indirect fluid communication with the synthesis gas outlet viathe desulfurization outlet of the desulfurization stage.

When numerical lower limits and numerical upper limits are listedherein, ranges from any lower limit to any upper limit are contemplated.While the illustrative embodiments of the invention have been describedwith particularity, it will be understood that various othermodifications will be apparent to and can be readily made by thoseskilled in the art without departing from the spirit and scope of theinvention. Accordingly, it is not intended that the scope of the claimsappended hereto be limited to the examples and descriptions set forthherein but rather that the claims be construed as encompassing all thefeatures of patentable novelty which reside in the present invention,including all features which would be treated as equivalents thereof bythose skilled in the art to which the invention pertains.

The present invention has been described above with reference tonumerous embodiments and specific examples. Many variations will suggestthemselves to those skilled in this art in light of the above detaileddescription. All such obvious variations are within the full intendedscope of the appended claims.

The invention claimed is:
 1. A method for hydroprocessing deasphaltedoil, comprising: performing solvent deasphalting in a deasphalting unitunder effective solvent deasphalting conditions on a feedstock having aT5 boiling point of at least about 400° C. to form a first fractioncomprising deasphalted oil and a solvent and a second fractioncomprising deasphalter rock and the solvent, the effective solventdeasphalting conditions producing a yield of deasphalted oil of at leastabout 50 wt % of the feedstock; recovering solvent from at least one ofthe first fraction and the second fraction, the recovering comprisinggenerating heat for the recovering by combustion of a solvent recoveryfuel comprising H₂; gasifying at least a portion of the deasphalter rockto form synthesis gas, the solvent recovery fuel comprising at least aportion of the synthesis gas; desulfurizing at least a portion of thesynthesis gas to form a desulfurized synthesis gas; separating at leasta portion of the desulfurized synthesis gas to form an H₂-enrichedstream; hydroprocessing at least a portion of the deasphalted oil in ahydroprocessing unit under first effective hydroprocessing conditions inthe presence of an H₂-containing gas to form a hydroprocessed effluentcomprising a sulfur content of 500 wppm or less, the H₂-containing gascomprising at least a portion of the H₂-enriched stream; forming a fuelsource by combining at least a portion of the synthesis gas and ahydrogen-containing purge stream; introducing a first portion of thefuel source to a deasphalting unit furnace; heating the deasphaltingunit by using the first portion of the fuel source in the deasphaltingunit furnace; introducing a second portion of the fuel source to ahydroprocessing heating unit; heating the hydroprocessing unit by usingthe second portion of the fuel source in the hydroprocessing heatingunit; purifying at least a portion of the desulfurized synthesis gas toform a hydrogen stream; compressing the hydrogen stream to form acompressed hydrogen stream; and introducing the compressed hydrogenstream to the hydroprocessing unit; separating the hydroprocessedeffluent to form at least a fuels boiling range fraction and a bottomsfraction; hydroprocessing at least a portion of the hydroprocessedbottoms fraction under second effective hydroprocessing conditions, thesecond effective hydroprocessing conditions comprising hydrocrackingconditions and catalytic dewaxing conditions, to form a catalyticallydewaxed effluent comprising a 950° F.+ (510° C.+) portion having a VI ofat least 80 and a pour point of −6° C. or less; and at least one of: a)solvent extracting at least a portion of the catalytically dewaxedeffluent to form a solvent processed effluent, and b) solvent dewaxingat least a portion of the catalytically dewaxed effluent to form asolvent processed effluent, wherein the catalytically dewaxed effluentis underdewaxed; wherein the solvent processed effluent has a cloudpoint of −2° C. or less.
 2. The method of claim 1, further comprisingcombusting at least a portion of the synthesis gas, the H₂-enrichedstream, or a combination thereof in a combustion zone of a gas turbinefor generation of electricity.
 3. The method of claim 1, wherein thesolvent deasphalting comprises deasphalting with a C₄ solvent, a C₅solvent, or a combination thereof.
 4. The method of claim 1, furthercomprising performing water gas shift on at least one of the synthesisgas and the desulfurized synthesis gas prior to separating the at leasta portion of the desulfurized synthesis gas to form the H₂-enrichedstream.
 5. The method of claim 1, further comprising heating the atleast a portion of the deasphalted oil prior to the hydroprocessing, theheating comprising combusting at least a portion of the synthesis gas,the desulfurized synthesis gas, or a combination thereof to generateheat.
 6. The method of claim 1, wherein separating at least a portion ofthe desulfurized synthesis gas to form an H₂-enriched stream comprisesperforming a swing adsorption process on the at least a portion of thedesulfurized synthesis gas to form at least the H₂-enriched purge streamand an H₂-containing purge stream.
 7. The method of claim 1, furthercomprising combusting a portion of the synthesis gas, the desulfurizedsynthesis gas, or a combination thereof in a combustion zone of a gasturbine.
 8. The method of claim 1, wherein hydroprocessing at least aportion of the deasphalted oil comprises demetallizing the at least aportion of the deasphalted oil, hydrotreating the at least a portion ofthe deasphalted oil, hydrocracking the at least a portion of thedeasphalted oil, or a combination thereof.
 9. The method of claim 1,wherein the yield of deasphalted oil is at least 55 wt %.
 10. The methodof claim 1, wherein the deasphalted oil has an aromatics content of atleast 50 wt % based on a weight of the deasphalted oil.
 11. The methodof claim 1, wherein gasifying at least a portion of the deasphalter rockcomprises gasifying deasphalter rock treated with an anti-tack agent.